Good afternoon. My name is Chris, and I'll 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 speaker's remarks, there will be a question-and-answer session. If you would like to register for a question, please press the one followed by the four on your telephone. 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 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 No. 2 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 plans 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. 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%-7% long-term growth rate expectation consistent with adjusted earnings per share in a range of $4-$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 3 and 4. 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 ITAAC. 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 three 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 of 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 60-80 years.
With this most recent change in project cost 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 MW of base load carbon free energy is vital to increasing the availability of net zero energy resources across the state. Considering these facts and our proximity to commercial operation, Georgia Power has already voted to proceed. The other owners are required to vote by March 8, which allows time for them to work through their own governance processes.
Consistent with a 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 differing interpretations of the cost-sharing agreement with an expected potential range of outcomes of $100 million-$900 million. We have included $440 million of the $900 million in our total project cost estimate. 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 MW of renewable generation by 2035, more than doubling Georgia Power's current renewable resources. Additionally, 1,000 MW 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 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 -$0.05 cent variance for weather as compared to 2020 and a -$0.14 cent variance compared to normal weather. Additionally, 2021 non-fuel O&M reflected a 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 areas. 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 will 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 the 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-$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%-1%, although a continuation of recent trends could deliver upside to that assumption. We continue to see long-term adjusted EPS growth in a range of 5%-7%, consistent with adjusted earnings in a range of $4-$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 serve to strengthen our outlook. Underlying our long-term adjusted EPS growth rate of 5%-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-$4.30. This forecast represents a $2 billion increase in state-regulated utility investment for the coming 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 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 plan 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 beginnings 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've 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 5 years could translate to investment opportunities beyond 2026 as we continue on our journey to net zero. Finally, we've included an updated 3-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 5-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 a 200-300 basis point increase from 2021 and 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 12-18 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-$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%-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.
Our first question is from the line of Julien Dumoulin-Smith with Bank of America. Please go ahead.
Hey, Julien.
Good afternoon, team.
Absolutely. Pleasure. Thank you.
Likewise.
Absolutely. Cool.
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. 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. You've got $180 million from the sharing band, and then above that sharing band, what percentage of the cost is borne to you, if you will. Can you kind of break down the sort of the successive pies, if you will? 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.
Julien , this is Dan Tucker. The 440 you absolutely hit it right. Within that is $180 million. That $180 million is consistent with the provisions in our agreement with co-owners, where Georgia Power bears a fixed percentage of incremental cost up to a certain point. 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. That number embedded in the 440 is $260 million. What that represents is Georgia Power's assumption of bearing $260 million, said a different way, 100% of all the dollars above the threshold. That 260 represents their shares already captured in the 480. This is capturing the co-owner's piece that is assumed in these numbers to be tendered. What was the second part of your question, Julian?
Well, COVID-related costs. I got a follow-up more holistic as well.
Yeah. As we've disclosed and we've 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. Rather than air those specific differences here on the call, let's let those conversations take place in the proper forum. 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.
Hey, 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, may be around 75 MW-80 MW. At the level in which we've estimated, we think it could be around 30.
That's correct, Tom.
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.
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.
Right. Exactly. Can you speak a little bit to this process then, right? You talk about this March 8th date with the co-owners here. Any initial indications on where they stand? You know, obviously this 90%-
Yeah
Is a high bar, but theoretically, they could vote to proceed. Then related to that, they could tender the incremental cost to you, right? I just wanna make sure I understand there are kind of two separate parallel processes here.
Yeah. 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 2019, 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 ways. 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.
Got it. All right. The processes are separate, and from their perspective, they could, in theory, vote to proceed and then ultimately allocate and tender their megawatts to you as you just talked about a moment ago, right?
They're two completely separate processes, yes.
They could decide to proceed.
Right.
Separately.
Yes
They can tender.
That's right. There's a 100- to 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. The ultimate calculation, we alluded to megawatts, we alluded to dollars. All of that would not get buttoned up until unit four was in service and all the costs were known.
Excellent. Thank you guys for the clarity. Dan, well stated.
You bet, Julien.
Thanks, Bud.
Our next question is from the line of Shar Pourreza with Guggenheim. Please go ahead.
Hey, Shar. Thanks for joining us.
Hey, Tom. It's actually James Ward on for Shar. Thank you for taking my question.
Oh, hey, James. Oh, you bet.
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. Yeah, 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 2027-2028 timeframe and then further again in 2035. The timeline to construct and frankly plan and permit these transmission projects is gonna take the bulk of this forecast period and spending really occurs beyond. The other-
Got it.
Just to detail, James, in the way you asked your question, I just wanna make sure it's clear there is some storage reflected in the capital forecast, but 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.
The only other thing I'll add.
Okay. The 250 is.
Yeah. 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 gonna be more solar? Is it gonna be combined cycle? Is it gonna be importing megawatts from the south to the north and therefore incremental transmission? We just haven't done all that work yet.
Okay. That's very helpful. 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. When you look at LDCs trading hands at nearly 2x rate base, how do you think about the opportunity to sell an asset at that level and then reinvest the proceeds into your decarbonization efforts at your electric utilities?
Well, I think we've demonstrated over the years that we're both, you know, 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. You know, 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.
In order to think about, you know, cap allocation as you do, and we think about it all the time, selling something like, you know, our asset in Illinois relative to reinvesting in the core, we always have to consider, you know, what's best for our long-term growth rate, what's best on a risk-adjusted basis. We'll continually do that.
Yeah. 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 great property.
Yeah.
Got it.
It would be purely a value play as opposed to a need.
Right. Gotcha. Then one final one here, just to follow on from Julian's question earlier. To clarify here, 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 reason that we should be aware of or that might be worth keeping in mind for why Oglethorpe or MEAG would not wanna proceed at this point since they have those cost caps in place? Just to help us understand.
We're not aware.
How they might be thinking.
We're not aware of any reason that exists like that.
Got it.
They have to go through their government processes, James.
Thank you very much. Those are all my questions. Thank you for taking the time.
You bet. James, thanks for joining us.
Our next question is from the line of Jeremy Tonet with JP Morgan. Please go ahead.
Hey, Jeremy.
Hi, good afternoon.
Good afternoon. I hope you're well.
Thanks for having me here.
Yes, sir.
Well, 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, you know, weighed in here on the ITAAC 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?
Yeah. Interestingly, I was just in Augusta, visiting with Glen Chick. I think he's just a superlative manager of the site, along with Stephen Kuczynski, and we actually went through different systems. At this point, and we are efforting to begin with the inspection report fix with what we believe are the toughest, hardest issues to deal with. Can't guarantee that, but so far, with 30% complete, we haven't found the 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. Nothing comprehensive as you're suggesting. Second question.
Well, was just curious, I guess, that's helpful there. Thank you for that. The NRC, if they've kind of weighed in on the ITAAC issues in any kind of-
Oh, NRC. Yeah.
Yeah.
Yeah. Thanks, Jeremy. Hey, you know, 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. 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 60-80 years. 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 wanna make sure that whatever we build is as appropriate to nuclear safety standards as exists in America today. They support our efforts to find these things.
I think, for the amount of ITAACs that we've already submitted, something like 275 or so, I think we've had very few problems with those ITAACs. 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.
Got it. That's really helpful there. 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. Do you think there'll be support to rate base suspension if the technology's 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.
Yeah. 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 ilk 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. 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. It also provides them a degree of resilience. I get that. We participate in SMRs. You should know that. 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 wanna 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 Generation IV reactors, the molten chloride salts. You know, we've worked with Bill Gates and his team on that.
You know, when you think about the R&D S-curve, I think we've done a lot of work on the science. 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 Generation 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 Generation IV reactors a commercial reality. In our own planning processes, they start to show up as an option probably in the late 2030s.
Let's say 2035 to 2040. As an economic matter, they tend to compete with CCS controlled combined cycle technologies. 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 Generation IV reactors. Again, that's an issue that's gonna 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, you know, 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 costs 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 reactor's meltdown characteristic could occur.
Very helpful. I'll leave it there. Thanks so much.
Thank you.
Our next question is from the line of Angie Storozynski with Seaport Global. Please go ahead.
Hey, Angie. Great to have you with us.
Thanks. I have a question I don't think I've ever actually asked a question about Southern Power. You know, I'm 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. You know, I struggle with your regions, with what Georgia, Alabama, and North Carolina. I'm not sure if that translates into higher dispatch or earnings of these assets. Again, if you could comment.
Yeah. 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.
Yeah. 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 gonna extend those units' coverage for another 10 years.
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.
Okay. Just moving on.
In fact, hey, Angie, somebody just showed me something else.
Yes.
Angie, excuse me, one more. I'll just give you one more data point. 95% contracted through 2026. 92 through 2031.
Very good.
That's the nerdy data.
Good. Now, just going back to Vogtle. So, yes, I've read—I actually just reread the agreement, the ownership agreement, and that additional background about COVID-related costs. So, you know, we're still seemingly in the COVID era, so I'm assuming that at least 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? Then secondly, you haven't mentioned inflation and so I'm just wondering how is that impacting the cost profile of this construction project?
Yeah, thanks for that. This is my opinion I'm giving you as opposed to fact, I guess. In my opinion, it is unquestionable. It is unreasonable to assume that COVID had no impact. The real art of the deal is to figure out how much of that impact manifested itself. If you dial back out 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 the Georgia Public Service Commission. I don't think we've updated those recently.
Certainly, I think any reasonable person would say that there have been COVID impacts on the site.
Yeah. 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.
I think we provided the chart in the appendix material. You can see even this most recent Omicron, it had an enormous spike in the December to January timeframe. Certainly it had an impact. We saw it, especially over the holidays. You know, we always expect to see more absenteeism and a variety of other things. We certainly saw it there as well.
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.
Let me hit one other kind of controversial point, but we watched this like hawks. Recall, at one time we had 9,000 people on site, and there was a lot of concern. Was this somehow a 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.
Yes. Thank you. How about inflation, though? Is it already embedded? In this additional cost estimate?
Yeah, Angie, most of the inflation sensitive stuff is already procured. Our supply chains are already spoken for, all the major equipment's there. I suppose there would be some labor. We're paying top decile right now. You know, I suppose that could come up later, but it hasn't been a big effect now.
Okay. Then the last question. You know, looking how strong your earnings were, I mean, have been actually over the last couple of years now, despite you know, unfavorable weather. Is the low 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 the people in the operating companies did. I'll tell you the big surprise. I said this on Squawk Box this morning, and the data we 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. We think 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 now and there 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, you know, 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.
Yeah. Just as you look at our forecast, look, we certainly haven't assumed that continues into the future because one year doesn't make a trend, but we reasonably believe it might. If you look at our forecast for residential sales for 2022, it actually reflects year-over-year negative. That's frankly mitigated by assumption of strong customer growth. 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. We're over 50,000 on the electric side. What was it? 27,000, something like that on the gas side. We continue to do that, and we think that is kind of a function too of people being able to work remotely. They tend to go to places that have low input costs, attractive place to live. Our economic development data shows that as well. I think some of the stuff, Dan, you talked about in the script.
Yep.
It just looks good, particularly for Georgia, but even Alabama's coming back and, we're doing well. We have reason to be bullish about the long-term viability of our franchise.
Very good. Thank you.
Thank you, Angie.
Thank you.
Our next question is from the line of Steve Fleishman with Wolfe Research. Please go ahead.
Hello, Steve.
Yeah. Thanks.
Hope you're doing well.
Good afternoon. Hey. Yeah, you too, Tom and Dan.
Thanks.
Two questions. First, just on the Vogtle, ITAAC issues. I know you knew all along that the paperwork and the trail of all that was super important, and you've been doing all the work. Kinda, could you give us a little flavor of, you know, just what has gone wrong here? 'Cause it, you know, obviously it's something that you were very focused on from the beginning.
100%, Steve. I think, you know, I said this in the media earlier, but it's true. I get up every morning throughout the day, in the middle of the night, thinking about Vogtle and what we can do and all that. The folks at the site have been particularly frustrated at this recent development. When we left you on the call in, 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, you know, load fuel and the whole bit. When we started getting into the final systems related to the final ITAAC. So right, 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 has 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, an important part of the paper are these inspection reports. 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, certify 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. You know.
Got it.
I am frustrated about it, but it is something we have to do. You know, 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. Totally separate topic. You were, I think, Tom, pretty accurate with caution about the Build Back Better getting done last year. 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, it's interesting, and I work with both sides of the aisle here. I think long term, both parties agree that we should do 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.
Great. Okay. I appreciate your thoughts. Thank you.
Yes, sir.
Our next question is from the line of Paul Fremont with Mizuho. Please go ahead.
Hey, Paul, always great to have you with us.
Thanks a lot. I guess my first question is gonna 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) . 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. On Unit 3, now I'm doing big chunky things. There's a little less than 100 systems, 96 or so. You would split those into 162 subsystems. Okay? There's 11 total to go. Since our last call, we've gotten five of those turnovers complete. If I think about what's remaining here, I would say that we have three to go for 103(g) and six to go on fuel load, and two that we can complete after fuel load. They're not necessary to the nuclear safety, side of things.
Great.
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 gonna update your estimate of COVID-related costs or not?
Yeah, the 444 was at 100% dollars. Our share of that was 160. I don't know the status of that. It didn't come up recently, so I think it's still an open issue.
Yeah. There was some degree of estimating future impacts.
Sure.
In the original number, and I think it's been consistent with that.
Yeah.
So-
We've not provided an update.
Is that 440 the sort of the most recent number that you've put out publicly? Yeah.
Yes. You typically see us disclose it as 160-200. That's our share.
Right.
The four- forty is a hundred thousand.
Okay.
Just to be clear, no change selected in VCM-26.
You're saying no change?
Correct.
In VCM-26. Perfect.
We just haven't created an addition based on the latest Omicron facts. I mean, clearly there were. We just haven't updated the estimate.
The numbers you put out for the cost-sharing potential write-offs are after-tax numbers.
Yeah.
Can we get pre-tax numbers for those? The $480 and the $440.
You want pre-tax?
Yeah.
Yeah, those are pre-tax, Paul. Those are pre-tax.
That adds $920. $686 is the after-tax portion.
Yeah. If you look in our deck on slide six, so then there's $920 listed there. That's pre-tax. Total after tax for that is $686. We've broken down the components. All that breakdown is pre-tax.
All that is pre-tax. Okay. The highest number of ITAAC that you've done in a given month, I think is 18. How confident are you in being able to sort of do mid-30 type numbers once you're able to sort of do the catch-up work on the documentation?
Yeah. Paul, what you have to understand and back where we were in October, November, we're basically finishing the work. What we found is the inspection reports were lacking. 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 this schedule.
And-
It's not that we're finishing construction.
In terms of the, are you completely done with all of the construction or the remediation work for unit three that you had identified sort of in the fall?
Yeah. 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. There's other examples, but that's it.
Okay. 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 plant. 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 material change?
I think the short answer, Paul, is no material change. These are market contracts. All of these contracts are being awarded to Southern Power under a competitive RFP process. It's gonna reflect the current market for those 10-year contracts.
Over the life of the contract, the IRRs would be similar. What we have said about the market broadly is that we've kind of pulled back from 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. 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. The last question for me, the 686, should we assume either equity or asset sales to fund that?
Yeah. Again, I think I said in my prepared remarks, Paul, that we don't see a need for equity in this five-year outlook. Let me just hit that a little more broadly because I think it's important. Look, absolutely nothing has changed about our near-term or long-term objectives when it comes to credit quality. Look, as we've said, kind of over the last, you know, several months, that as we move closer to completion of the project, any change in the cost or schedule, we'll 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. Frankly, we did a little bit more than what was needed. That has positioned us really well.
I wanna 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 2023, 2024 timeframe. That also is near enough in time horizon to give us comfort with our overall financial profile.
Great. I think that's it in terms of questions. Thank you.
Awesome.
Our next question is from the line of Michael Lapides with Goldman Sachs. Please go ahead.
Hey, guys. Tom-
Hey, Michael. How you doing?
I'm all right, guys. Thank you for taking my question. I appreciate you taking the time. Commodity prices are up across the board. Obviously, that's a bigger issue than any one, you know, 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, you know, the commodity exposure. How should we just think about the bill across your biggest businesses? I'm thinking Alabama Power 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 2023 as well?
It's interesting stuff, man. When you look at the data, gas prices increased 2021 versus 2020, 92%. Like, we averaged, I think, $3.82 per million BTU versus $1.99 a year ago. 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. It 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. 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 impacts to the service territory, and you've got a high growth service territory relative to a lot of your peers, how do you think about it when you meet with folks outside of the company about what it means for economic growth?
Yeah. You know, 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. That's essentially 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 sodas 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, you know, 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 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. There will be a slowdown in the economy. Now, the real, you know, $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. For the lead time to procure certain goods and services, it is really sticky right now. 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. 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, some 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's 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.
Yeah. Michael, this is Dan. You know, right now we're not in a big construction period, and so we're fortunate to not be experiencing, you know, as acutely as some of our peers right now, some of those delays. We've seen some. We are in the middle of a storage project out in California. We've seen some modest delays, but nothing that's gonna impact the project overall. It's the supply chain and then really combined with you know, 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.
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. 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 Deputy Secretary David Turk, who's a terrific guy. You know, as a matter of national security, as a matter of economic opportunity, one of the things that we need to do as a nation is resource these important supply chains domestically that will grow manufacturing, grow jobs, grow personal incomes. It's a real winner. 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 gonna happen immediately. People are considering it, and I bet you would get broad bipartisan support for that strategy.
Got it. Thank you, Tom. Thanks, Dan.
You bet, Michael.
That does conclude our question and answer session. Sir, are there any closing remarks?
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. Now with this delay, it looks as if, you know, 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. 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, on our partners, Bechtel. When we build this thing, 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 gonna 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 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. We're very proud of that. I wanna 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 in 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. Our financial position, the integrity of this company will be better than it ever has been in my experience. 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.