Earnings Call Transcript
SOUTHERN CO (SO)
Earnings Call Transcript - SO Q3 2021
Operator, Operator
Good afternoon. My name is Myra, and I will be your conference operator today. At this time, I would like to welcome everyone to the Southern Company's Third 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. I would now like to turn the call over to Mr. Scott Gammill, Investor Relations Director. Please go ahead, sir.
Scott Gammill, Investor Relations Director
Good afternoon and welcome to Southern Company's third quarter 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 that 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-Q 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 Fanning.
Tom Fanning, CEO
Thank you, Scott. Good afternoon and thank you for joining us today. As you can see from the materials released this morning, we reported strong adjusted results for the Third Quarter. The economies in our service territories continue to recover from the COVID-19 pandemic, and in particular, customer growth continues to exceed our expectations. Given results through September, we expect full-year adjusted earnings per share to be above the top end of our guidance range. Dan will share more on this in a moment. So let's begin with an update on Vogtle Units 3 and 4. Two weeks ago, we updated our expected completion timeline for both units, extending the in-service dates by 3 months. For Unit 3, following the completion of hot functional testing, we completed walk down of the 158 safety-related rooms within the nuclear island to assess the extent of remediation work required, consistent with the electrical installation quality issues we highlighted earlier this year. The number of instances of items needing remediation found during our full assessment process, however, exceeded our estimate from July. The change in the Unit 3 schedule into the third quarter of 2022 is primarily a function of the time needed to address the full scope of the remaining remediation work and to account for the impacts on productivity resulting from higher than expected attrition and slower than expected onboarding of new electricians, field engineers, and supervisors. For Unit 4, recent progress has slowed. The craft labor and support resources have been temporarily shifted to support Unit 3's completion efforts. Considering this decrease in available resources over the next several months, plus recent productivity trends, we now expect Unit 4 in-service during the second quarter of 2023. Importantly, with the corrective actions we implemented after discovery of the Unit 3 quality issues, including reinforcement of the importance of first-time quality with craft personnel, and improvements to the application of Bechtel's quality program, we believe that as we turn systems over on Unit 4, the amount of remediation work required will be less than what we experienced on Unit 3. During the third quarter, consistent with the surrounding areas, the site experienced a spike in COVID-19 cases that approached the peak of cases we experienced early in 2021. While the availability of vaccines and well-established protocols helped preclude the same degree of disruption experienced during the first wave of COVID-19, the pandemic was certainly a contributing factor to overall productivity and resource availability. For Unit 3, repairs to the spent fuel pool, system turnovers, and ITAAC submittals continued throughout the third quarter. Repairs to the spent fuel pool are now complete. The next major milestone for Unit 3 will be the receipt of the 103 G letter from the NRC. To date, 242 ITAAC have been submitted to the NRC with 156 remaining. On Slide 7 of today's earnings call deck, we have included a forecast of the remaining ITAAC submittals required to support a projected May 2022 fuel load and third quarter 2022 projected in-service date. Now, considering our recent volume of ITAAC submittals in October, and the expected completion and turnover of significant systems in the months ahead, the site is targeting ITAAC completion earlier than what is indicated in this forecast, which would provide margin to Unit 3's remaining schedule. We expect to use the time between ITAAC completion and fuel load to finalize the non-safety-related elements of the plant and to complete any remaining pre-fuel load testing. Turning now to Unit 4, direct construction is now approximately 89% complete. A revised projected in-service date of the second quarter 2023 reflects the temporary shift of services to Unit 3. Recent productivity trends on bulk electrical work and ongoing efforts to add craft labor and non-manual field support resources in support of first-time quality and productivity are ongoing. Construction completion for Unit 4 has averaged 1.4% per month since the start of the year. To achieve a second quarter 2023 in-service date, Unit 4 would need to average approximately 1% construction completion per month through the end of 2022. From a cost perspective, Georgia Power's share of the total project capital cost forecast increased by $264 million, largely driven by our updated schedule, productivity consistent with recent trends, the cost of additional resources to complete the full scope of remaining work with necessary focus on quality and the replenishment of contingency. As a result, Georgia Power recorded an after-tax charge of $197 million during the third quarter. We remain committed to the credit quality of Georgia Power and Southern Company, and we will continue to seek to maintain strong credit metrics for both entities. Our priority is bringing Vogtle Units 3 and 4 safely online to provide Georgia with a reliable, carbon-free energy resource for the next 60 to 80 years. We're committed to taking the time to get it right. We will not sacrifice safety or quality to meet schedule. At Unit 3, we are working to submit remaining ITAAC to support receipt of the 103 G letter prior to fuel load and commercial operations in 2022. For Unit 4, we remain focused on attracting and retaining necessary craft labor and support resources, as well as first-time quality as we work to increase productivity and progress towards the start of open vessel testing, which is now projected by the second quarter of 2022. Dan, I will turn the call over now to you for an update on the financials.
Dan Tucker, CFO
Thanks, Tom. Good afternoon, everyone. As you can see from the materials we released this morning, all of our major subsidiaries had a solid quarter, and our adjusted consolidated earnings are trending extremely well through the third quarter. For the third quarter of 2021, we reported earnings per share of $1.23 on an adjusted basis, $0.01 higher than both our estimate for the quarter and our adjusted third quarter of 2020 earnings per share. For the 9 months ended September 30th, 2021, we reported adjusted earnings per share of $3.05 compared with adjusted earnings per share of $2.78 for the same period in 2020. A detailed reconciliation of our reported and adjusted results is included in this morning's release and earnings package. Major drivers for our adjusted earnings results for the third quarter of 2021 included higher retail kilowatt hour sales at our state-regulated utilities, as we continue to see recovery from the pandemic, strong customer growth and impacts of several constructive regulatory outcomes, partially offsetting these impacts; non-fuel O&M reflects the trend towards more normal operating conditions relative to 2020. Milder than normal summer temperatures in the Southeast also negatively impacted earnings per share by $0.02 compared to our estimate and by $0.07 compared to the third quarter of 2020. Turning now to customer growth through September, we have added over 40,000 new residential electric customers and over 20,000 residential natural gas customers across our regulated utilities. This level of customer growth has exceeded our forecast year-to-date and puts us on track to surpass last year's customer growth levels, which were also above historical norms. Customer growth continues to be driven by a strong labor market recovery, which is on track to reach pre-pandemic levels of employment in our Southeast service territory next year. For the third quarter, weather-adjusted retail electric sales were up 3% compared to last year and were in line with our expectations. Residential sales remained higher than expected due to extended remote work practices, and commercial sales showed continued improvement, coming in slightly better than our forecast. Industrial electricity usage lagged other customer groups, primarily driven by production cuts from a single large customer in the chemical segment. This customer-specific event has resulted in industrial sales being in line with our forecast for the quarter. We continue to analyze retail sales, and in aggregate through the third quarter, our retail sales have essentially recovered to 2019 pre-pandemic levels. We are encouraged by these positive signals while we also continue to monitor the potential impact of the COVID-19 variant, supply chain constraints, and labor force participation. The economic development pipeline in Southeast remains robust. Job announcements and business investment in Georgia in the third quarter of 2021 were higher than pre-pandemic levels for 2019 and the average of 5 years ending 2020. In Georgia alone, there are currently over 200 active projects with the potential to bring in nearly 40,000 jobs and $13 billion in capital investment in the coming years. Next, I'd like to provide you with an update on our outlook for the remainder of 2021. With adjusted earnings per share through September of $3.05, we expect to achieve adjusted full-year earnings above the top end of our guidance range of $3.35 per share. Our estimate for the fourth quarter is $0.35 per share, which implies estimated full-year results of $3.40 on an adjusted basis. Before turning the call back over to Tom, I'd like to follow-up briefly on his update on Units 3 and 4. First, I want to reiterate our commitment to credit quality, which has been constant. In our last call, we reinforced that commitment by announcing we would turn on our dividend reinvestment plans in the near future. As we have done so well over the last several years, we also continue to evaluate opportunities for asset sales. Within a portfolio the size of Southern Company, we have several investments that warrant continuous review for whether or not a better owner exists. Whether such potential transactions serve to offset our near-term equity needs or ultimately fund our long-term capital investment plans, we will remain disciplined to the benefit of equity holders and bond holders alike, as we execute our financing plans. And finally, let me briefly highlight the Vogtle Units 3 rate adjustments stipulation that was unanimously approved by the Georgia Public Service Commission on Tuesday. This most recent order allows $2.1 billion of investment in Vogtle Unit 3 and the Vogtle Units 3 and 4 common facilities to be moved from the Nuclear Construction Cost Recovery tariff or NCCR into retail rate base the month after Unit 3 goes into service, where it will earn Georgia Power's full allowed rate of return. Additionally, Georgia Power will be allowed to recover the related operating expenses and depreciation on this portion of Unit 3, which is an important credit supportive aspect of the stipulation. The entire process, which struck an appropriate balance for all stakeholders, was a great affirmation of the constructive Georgia regulatory environment. Tom, I'll now turn the call back over to you.
Tom Fanning, CEO
Thanks, Dan. Let me wrap up with an update on the Southeastern Energy Exchange Market or SEEM and our fleet transition. Subject to resolution of any rehearing requests, SEEM is moving forward after clearing the approval process. SEEM is a region-wide automated platform consisting of nearly 20 entities across 11 states, with the goal of more efficient bilateral trading in the Southeast. It is not an energy imbalance market or an RTO. Benefiting from robust integrated planning by the individual states, municipalities, and utilities, the region represented by SEEM members scores very favorably on all important metrics compared to the RTOs across the country. SEEM will improve electric service to customers in the Southeast, a region that is already an industry leader for customer satisfaction and reliability. The members of the SEEM electricity market also provide low retail prices for residential and business customers using a mix of carbon-free energy resources similar to the rest of the country. We believe SEEM is good for our customers, and we're excited to be a part of this new platform, which is expected to launch in mid-2022. Turning now to our fleet transition. In our most recent climate report named Implementation and Action Towards Net Zero, we reaffirmed our long-term goal of achieving net-zero greenhouse gas emissions by 2050. As an important step in the transition of our fleet, earlier this month, Alabama Power and Georgia Power filed plans with their respective state environmental authorities detailing how each would comply with the U.S. Environmental Protection Agency's Effluent Limitation Guidelines. With these expected changes and the recent retirement announcement of two coal units at Mississippi Power's plant, since 2007, Southern Company will have announced total decreases in its coal-generating capacity from more than 20,000 megawatts across nearly 70 generating units to less than 4,500 megawatts of coal capacity remaining at 8 generating units. This equates to a reduction of nearly 80%. The final resolution for many of the actions outlined in the compliance filings, including the exact timing of retirements and any other actions we may recommend remains subject to the approval of our state public service commissions through the integrated resource planning processes or IRP. These proceedings are intended to comprehensively address transmission and generation resource needs over the long term, which could include additional decisions regarding the future of the remaining coal unit. As always, part of our planning process for transitioning these units will include placing a high priority on protecting the interests of our employees and the communities we are privileged to serve. The transition of our generating fleet and the important regulatory proceedings that will play out over the next 9 months, will significantly inform our capital investment opportunities. As we always do, we will update our capital investment plans during our fourth-quarter earnings call early next year, which will include known fleet transition opportunities. It is likely that further transparency on our long-term capital plan will unfold throughout 2022, and we will update our forecasts as appropriate. Importantly, our current 2024 earnings per share base of $4 to $4.30 is based upon our current 5-year capital plan with potential incremental investments providing the opportunity to strengthen our position, both within that 2024 range and within our 5 to 7% long-term growth range. Now, before we move to the Q&A portion, which we always love here, this just came across the wires. Next week is Veterans Day, and a publication that I'm sure you all know well, Military Times, came out with their Best for Vets ranking of employers. We've been on the list that shows the top 15 companies across America and it includes well-known companies like Bank of America, Booz Allen Hamilton, The Hilton Group, Johnson & Johnson, and others. They just named Southern Company the number 1 Company in America that's best for vets. That included evaluations of recruiting practices, retention, and support programs and a higher emphasis on employers that provide assistance and flexibility for individuals in the guard and reserves. We certainly respect the contributions that these folks make. They are a significant part of our employment base, comprising over 11% of our employees today. We respect their service, and we want to make sure they have the best work environment possible. We are honored beyond belief to be named the number one Company in America, Best for Vets, as named by the Military Times. Thank you for joining us this afternoon. Operator, we are now ready to take questions.
Operator, Operator
Thank you. You will hear a 3-tone prompt to acknowledge your request. One moment, please for our first question. Our first question comes from Shar Pourreza with Guggenheim. Please, go ahead.
Shar Pourreza, Analyst
Hey, guys.
Drew Evans, CFO
Hello, Shar, thanks for joining.
Shar Pourreza, Analyst
Excellent. Dan, nice to hear your voice. Just a couple of quick questions here. Tom, a lot of investors are hoping to hear more about your capital expenditures opportunities at the EEI next week, especially with your Georgia and Alabama IRP next year. Can you remind us of some of the types and size of the incremental capital expenditures we could see when you roll the capital expenditure plans forward next February? Maybe offer some ballpark figures to help frame the opportunity set as you shut down coal, how you'll finance it, and what the impact on rates could be. I mean I understand things will shift between now and then, but any comment would be great.
Tom Fanning, CEO
Yeah. Sure. I hate to disappoint you. We're not going to say very much next week. Suffice to say that each plan and approval by the public service commissions will have an impact on capital expenditures. We always provide that update in our call. I guess it will be the end of January or early February, about our fourth-quarter results and total year results. So, we will certainly do that then. I think as I said, to the extent there are impacts, the current capital forecast formulated our range in 2022, $4 to $4.30. To the extent there is an increase in capital expenditures, certainly that strengthens our place within that range and the longer-term 5% to 7% growth rate. The other thing we should remember about rates is that as you retire coal, you free up a whole lot of O&M. We intend to use that O&M to basically allow for cost recovery, account for the incremental revenue requirements associated with new generation that will replace that and keep rates as low as possible for our customers.
Drew Evans, CFO
And so just as a reminder what Tom's remarks is, the $4 to $4.30 in 2024 is predicated on our current capital expenditure plan. The way to think about these incremental opportunities is that it will potentially increase or intensify, overcome. I mean, you said postpone growth. I think that is the point in time when we really begin to see tangible long-term increases to that profile from $8 billion a year to something more.
Tom Fanning, CEO
One last point to mention is that one of the advantages of our integrated resource planning processes is that we can optimize portfolios not just in generation but also in transmission. So there could be a benefit in transmission. Additionally, it's important to remember that we currently allow around $500 million a year for capital allocation to entities like Southern Power. None of these allocations are included in our forecast. It makes sense that as the U.S. shifts its generating fleet, there will be more opportunities for Southern Power in this context.
Drew Evans, CFO
Just on the transmission, Shar, the reason we're being a little hesitant to share too early, there's transmission opportunities associated with what we will retire. The other transmission opportunities come about with what we replace that with and where, and that is simply a function of our integrated planning processes, and we just need to let those play off.
Tom Fanning, CEO
But it's a good thing for us. A good thing for our customers we get to iterate around those choices. You don't get that opportunity in the organized markets.
Shar Pourreza, Analyst
Got it. Thank you for that. And I know lastly for me, I know there's a lot of focus on exactly which month in the three will be in service next year, but I'm a little bit more interested in what happens once it's online. So once you get Unit 3 online, how should we think about what that means for earnings and cash flows in light of the TSC proven that joint settlement with the staff this required? I know there's a lot of moving parts with the NCCR AFDC. The penalty ROE, but just really at a high level, what are the immediate impacts to cash flows and earnings following Unit 3 reaching the service? Thanks, guys.
Tom Fanning, CEO
Yes, absolutely. So let's just make the assumption for the sake of describing all this chart that the third quarter means September of 2022. Given the results at the Georgia Public Service Commission earlier this week, that will mean that rates will go into place for $2.1 billion of Unit 3 in the common facilities, earning Georgia Power's full cost of capital. If you think about it, relative to what we're earning today, that's going to add about two-thirds of a cent of EPS for every month, for October, November, and December relative to what you would have forecasted under current conditions it's about two-thirds of a cent per month.
Drew Evans, CFO
Important thing is that $2.1 billion is not the full cost of Unit 3 and the common facilities, what remains will remain earning a return under the NCCR or will be deferred for future recovery with the Commission. At the same time, we will be recovering currently the operating costs of Unit 3 and the depreciation, at least associated with a $2.1 billion.
Shar Pourreza, Analyst
Got it. That was super helpful. Thanks, guys. I appreciate the great execution.
Drew Evans, CFO
Thanks, Shar.
Tom Fanning, CEO
Thank you.
Operator, Operator
Thank you. Our next question comes from Julien Dumoulin-Smith with Bank of America. Please go ahead.
Tom Fanning, CEO
Hey, Julien, how are you?
Julien Dumoulin-Smith, Analyst
I'm doing quite well, thanks, Tom. Congratulations to the clinical team and Dan too. Let's get straight into the asset sale for the year. You made some interesting comments earlier, and I wanted to clarify your thoughts on regulated assets compared to some of the other assets you own, like Southern Power. What are you considering in that regard? More importantly, what are your thoughts on equity needs? It doesn't seem to be explicitly stated as substantial at the moment, but can you discuss your considerations around equity needs, especially in light of the potential capital expenditures you mentioned? I believe that will relate to your commentary on asset sales as well.
Tom Fanning, CEO
Yes, sure. As always, Dan will speak to the equity needs. I'll go back to the litany on M&A that I always do. I think we've demonstrated in the past whether we're buying or selling, that we always seek to put assets with the best owner. Our formulation for that is the old rubric, value is a function of risk and return. We have ideas right now, but we really don't want to front run in the public what those ideas are about assets where there may be better owners. We'll see whether they come to fruition or not. Certainly as they do, we will keep you updated, but we are looking over our list of things and we'll see. Dan, you want to speak to the equity needs?
Drew Evans, CFO
Yes, absolutely. So Julien, essentially, what we're addressing is only the impact of the recent Vogtle cost increases. To the extent that has an impact on our credit profile, we're committed to mitigating that. Whether that's turning our drip on or finding opportunities with these asset sales. Beyond that, we still see a long-term plan, even in light of the incremental capex opportunities that we're alluding to, where we don't need incremental equity. I think it's important to point towards a post-Vogtle kind of forecast period. Our credit metrics out there are about 200 basis points for FFO to debt higher than they are today. That's a position of strength for us and gives us a lot of flexibility as to how we finance our group. I just want to clarify, just back on the source question that I said two-thirds of a cent per month. It's two-thirds of a cent per month, I just want to make sure that's clear.
Julien Dumoulin-Smith, Analyst
Two-thirds of a cent.
Drew Evans, CFO
Yeah.
Tom Fanning, CEO
Okay. Yeah. And to be very clear, Julien, I'm trying to be less elliptical on what we're looking at. But you should assume, as we have moved here to be, what is it, 95% of our earnings are integrated regulated kind of earnings that it would contribute to that profile. In other words, we're not going to buy ourselves things which make ourselves more risky. I think we love the idea of reasonable return and low risk. Also, as you have seen in the past years or since I've been here. As we have bought, say for example, AGL Resources now Southern Company Gas, there have been things around the edges that have allowed us to simplify and de-risk our business. So think about those things and we'll see how it goes.
Julien Dumoulin-Smith, Analyst
Excellent. And then just coming back to Unit four, obviously, you made some comments a moment ago about some of the labor availability, etc., and remediation work. I mean, how do you get comfortable with the nine-month time gap between those two units in-service date? But I'm just calling out that staffing stated at various points about the concerns that they have, on the second unit in-service.
Tom Fanning, CEO
Yeah. Julien. Yes. Thanks for that. It's an important point to raise as it ties at both ebbs and flows here. Let me explain that a little bit. We believe that Bechtel has had the responsibility to attract skilled personnel, skilled craftwork, especially electrician engineers, to assess the work that's being done and field site personnel, supervisory personnel to oversee the work that's going on. We have not kept pace with the requirements to advance these units in terms of attracting the people, and you named the reason why we've had more attrition. I think certainly the amount of attrition is potentially associated with the COVID response and everything else. So we've had to do a couple of different things. We have said in the past that we were moving to de-link the progress at Unit 4 from Unit 3. Therefore, this 12-month margin didn't matter. One of the way that we serve to continue to advance Unit 3 was again to borrow personnel from Unit 4. We didn't really want to do that, but it was a necessary move to continue to advance the work at Unit 3. Now, as we finish that work, we will send those people back to Unit 4. Once again, they will be de-linked. But for the period of time in which we have borrowed personnel from 4 to 3, a delay in 3 means a delay in 4. So that has happened. The other thing we have done is to augment backfills, sourcing efforts with our own efforts. We've had a very deep engineering and construction services group in Birmingham, our own resources that we could attract personnel, and we have significantly augmented Bechtel's efforts to increase the flow of people necessary to promote skilled labor, electricians, and field supervisory personnel. All of those things are in progress. All of those things are consistent with the new schedules we've given you. I would say one more thing. There was a lot of conversation about this. Both Chris Womack and I, in particular, are really watching the trends. If I just looked at current data, we still have margin, six weeks or so to Unit 3, three months or so to Unit 4, on the existing but not extended schedules. We looked at the trends, however, and the trends, to me, were troubling. We all kind of stepped back and said, I would rather take the conservative posture of evaluating these trends and adding more time, because frankly, we didn't believe that we had six months of scheduled margin left on 3, and three months of scheduled margin left on 4. We could have quibbled on adding a month or two months. We said, let's go ahead and add a quarter for both, and that's where we came out on this decision.
Julien Dumoulin-Smith, Analyst
Got it. So it's not so much the nine months necessarily. It's that you're adding a quarter of both of those latitude within both schedules. If I'm hearing you right.
Tom Fanning, CEO
Yeah. The only time they are linked is when we borrowed from 4 to 3. Therefore, a delay in 3 causes a delay in 4. Once we get 3 back into its place, then we are able to send the people back to 4. Again, they are de-linked. The nine-month difference between the two does not trouble us.
Julien Dumoulin-Smith, Analyst
Got it. Okay. I'll leave it there. Thank you, guys. Best of luck. Hear from me soon.
Tom Fanning, CEO
Thanks. Appreciate you calling in.
Operator, Operator
Thank you. Our next question comes from Steve Fleishman with Wolfe Research. Please go ahead.
Tom Fanning, CEO
Great. Good afternoon, Tom. Likewise. Dan, nice to have you as CFO. Just first on the Vogtle schedule. I know you don't want to speak for the commission, but just with this latest update in the way that you're giving schedules now, is there a better chance that they'll match up closer to what you are saying when they come out in a few weeks on this or should we be prepared for something that's again different than what you're saying? Yes. Steve, you kind of gave me the answer before I answered, and that is I don't want to speak for staff. Dr. Jacob is a guy that I know well. He attends the same meetings we attend; he sees the same stuff we see. He's a really bright guy. I think if I had to highlight something that will come under some discussion, and I think it's absolutely correct, you want to look at schedule variability at this point. We believe we see a pretty clear track to receiving the 103 G letter, which allows us to load nuclear fuel and allows us to go hot on the site. There is a certain amount of work that will occur between the receipt of the letter and the actual loading of nuclear fuel. In my opinion, that work from 103G receipt to loading the fuel is probably the remaining biggest risk to schedule that remains on Unit 3. Recall in the script, we talked about finding more remediation. I know in some other media, we've talked about these items. None of them are deal killers, and all and stuff, but there's no such thing as a little issue in nuclear. Everything we take seriously. Everything must be done effectively and with perfection. That is the time that we're looking at right now that I would say to you is probably the shared view of Dr. Jacobs in particular and us, as the biggest risk to schedule that remains right now. Our assessment of that work, if we get the 103 G letter early, let's say January, then I'm going to guess, and this is just a guess on my part, so don't hold me to it, but I'm going to guess there may be six weeks of work left from receipt of the letter to the actual loading of the fuel. If the 103 G letter is delayed, then that six weeks reduces because this is work that can be done in parallel with, some of the other stuff that's required to get 103 G.
Drew Evans, CFO
Let me just add real quickly to Tom's comments. The nature of the risk for that work Coast 103G up to fuel load is really logistics. Once we receive 103G, the site becomes an operating nuclear site. The logistics of getting people to ingress and egress a personnel to do the remaining work is just friction on productivity, and that's really the nature of that risk.
Tom Fanning, CEO
That was helpful.
Steve Fleishman, Analyst
Clear that was very helpful. And Dan, going back to the question before about trying to kind of size the potential equity needs or asset sale target needs. You said just look at the what's the cost increases have been. Is that as simple as that or are you targeting any different metrics as well?
Drew Evans, CFO
Yes. Look, Steve, if you want to make an assumption in your model that our opportunity to do that is the size of the after-tax write-offs, that's a reasonable assumption. That said, we're looking across multiple opportunities. We will see what that looks like. More importantly, from a long-term perspective, the uplift in the credit metrics that we talked about is really key. We always take a long-term view on this stuff, and I'm very comfortable with how we're positioned long-term and there's not a need for anything significant more than those near-term charges that we've taken to earn.
Steve Fleishman, Analyst
Okay. And you haven't mentioned anything significant more than those near-term charges that we've taken to earn.
Tom Fanning, CEO
Go ahead, Steve. Go ahead.
Steve Fleishman, Analyst
You haven't provided a number regarding the DRIP equity that you mentioned turning on. Did you?
Drew Evans, CFO
We have. Yes, we have. So we've not turned it on, we're holding that as an option to see what, if anything, becomes of any asset sale opportunities and we'll do one or the other. The DRIP on an annual basis equals about $400 million worth of equity.
Tom Fanning, CEO
And in a prior call, you kind of said we thought the DRIP and one year without the last issue. This is another roughly $200 million. Let's see what the review of our asset sales are, and we'll figure out where we go on the issuance of new shares under the DRIP. Please assure if we can find a better solution than issuing shares under the DRIP, we will do it.
Steve Fleishman, Analyst
Right. And I guess to the degree that there might be some incremental growth opportunities in the capital plan as you go through IRP transition, etc., asset sales could help fund that part too.
Tom Fanning, CEO
Yes, I think it's good and as Dan indicated, from the capex forecast, most likely the capex opportunity associated with the transition of the fleet will occur in the back part of that capex forecast.
Operator, Operator
Thank you. Our next question comes from Jeremy Tonet with JPMorgan. Please go ahead.
Tom Fanning, CEO
Hey, Jeremy, how are you?
Jeremy Tonet, Analyst
Good, Thanks for having me. Just wanted to come back to Vogtle. If I could here, just wanted to see if you could provide some incremental color on labor market impacts here and just as I'm thinking, how much just costs go up per month delayed at this point, just this prior increase seems a bit larger than I would have thought.
Drew Evans, CFO
Jeremy, the way to think about it, this has really been what has occurred both in the second quarter and this most recent announcement here in the third quarter, the cost increases have really been a function of two things. One is the schedule itself, and that's kind of that notion of hotel load that we talked about. For Unit 3, that is $35 million a month, I believe, and for Unit 4, $25 million a month and $15 million a month for Unit 4. For every month reaching, if that's just the infrastructure that supports construction and the cost of that. With this most recent increase and again, much like the second quarter increase, it also came with new assumptions on the number of personnel necessary to complete the work, and so that's where that incremental cost is coming from; both increases really represented about half pure schedule or hotel costs. The other half, personnel and productivity assumptions to complete the work.
Tom Fanning, CEO
Yes. I would be remiss if we didn't had the idea that in sourcing all of these personnel in the skilled labor. Sean McGarvey and his team at the building trades have been fabulous. The IBEW in particular has been great, they've given us tremendous ongoing support. I think our relationship with them is really bearing fruit here as we augment that builds efforts.
Jeremy Tonet, Analyst
Got it, that's helpful. Thank you for that. And maybe just shifting towards the DC for a minute here if I could. Obviously, things are fluid here, but just want to see as things stand right now, what are your biggest takeaways from the federal infrastructure legislation? And when thinking about minimum taxes, well, I guess how do you think some of the gives and takes as it relates to Southern?
Tom Fanning, CEO
Calling the situation in Washington fluid is an understatement. There is a lot of positive content in the infrastructure bill and in the reconciliation bill that benefits us. These bills are primarily designed as incentives, which we believe are the right approach. We are especially focused on ensuring that as we transition our fleet and transmission systems towards a net-zero future, we keep prices as low as possible. This is crucial for maintaining our competitiveness in the global energy market and for enabling America to strongly compete for new loads, manufacturing, and other opportunities. It's vital for our customers to have low prices and for us to provide sufficient incentives. Regarding the minimum tax proposal, we think its impact on us will be limited. While it may fluctuate from year to year, it typically averages around 1%.
Drew Evans, CFO
That's right, Tom.
Tom Fanning, CEO
So I don't have much of an impact on us. I'm sure it would for others that rely on tax benefits to drive their earnings.
Jeremy Tonet, Analyst
Got it. That's helpful. Thank you.
Operator, Operator
Thank you. Our next question comes from Michael Lapides with Goldman Sachs. Please go ahead.
Michael Lapides, Analyst
Hey, everyone. Thank you for the question. Congratulations to Dan for being a talented person in the CFO role within a large company that has a lot going on; it's well-deserved. I'm thinking about the regulatory calendar and how the events may connect or not. You'll go through the IRP process, and I'm unsure if the IRP requires formal approval. Additionally, will you still have a rate case, and will you also file to bring Unit 4 into service like you did with Unit 3 to determine the revenue requirement?
Tom Fanning, CEO
So Michael, there is a laundry list of things going on next year. We're certainly taking all of that into account. If you look at history, the Georgia Power Company with its relationship with the PSC itself, and what the workload at the staff, I think we've always managed to find our way to get big things done. We just look forward to that constructive relationship going forward. I think the recent settlement agreement we reached on the stuff we just mentioned in the script was evidence of that continued good working relationships. There is a lot going on next year with VCM, with IRP, with Vogtle 3, with potential prudency earnings beginning on the fuel load of 4, and with a rate case filing. So there's a lot to work through. Just to understand that as we have in the past, we'll work with the folks involved to do it in the right way.
Michael Lapides, Analyst
Got it. My other question, and I saw a little news splash for the past week or so about you buying a plant from AI infrastructure private equity owner to serve. I think it was for Alabama Power. Just curious, when you look around, do you see significant opportunities for kind of plant M&A to bring them into rate base versus going through the construction process?
Tom Fanning, CEO
Yes, we do. We keep those things, just as we're talking about buying and selling, and we want to kind of keep our kimono closed at this point, as we see those opportunities we'll certainly work on them. That's just another evidence of something. The other kind of good thing about buying used assets that way. As you think about transitioning the fleet, I think I've said this in the past, to get to zero for us we're going to have a profile in the 2040 to 2050 that will look something like 50% renewables, maybe 20% nuclear, maybe 25% natural gas. A lot of that natural gas will have CCS on it. The tail end of that, the 5% remaining could be something different. It could be hydrogen; it could be a variety of other things. Hydrogen doesn't appear to be all that viable until maybe in the 30s. You do know that the Plant Alabama is building has the capability to blend hydrogen into its fuel mix. So you may see hydrogen occur in an indirect sort of way prior to the 40s and 50. My sense is that you're going to have a lot of opportunities to buy some natural gas. The good thing about buying used units is they may have a remaining life of 10 to 15 years that fits in with retirement schedules that are consistent with adding more renewables. So those assets look like bridging assets and are very attractive economically and important to our strategy of replacing it with renewables.
Michael Lapides, Analyst
Got it. Thank you, Tom, much appreciated.
Tom Fanning, CEO
You bet. Always good talking with you.
Operator, Operator
Thank you. Our next question comes from Paul Fremont with Mizuho. Please go ahead.
Tom Fanning, CEO
Pleasure to have you with us.
Paul Fremont, Analyst
Thank you so much. You've talked a little bit about you still have construction work remaining on the plant. Can you give us a timeline that it's going to take for you to complete the construction and if you want to sort of separate out the third bucket that you think you can do after you get the letter?
Tom Fanning, CEO
Okay. So in general, what I indicated was here we are in nearly the middle of November. So in order to hit January, 103G. So that's two months round numbers. I would say if we had 103G in hand in January, my best guess right now is there may be another six weeks of construction. So let's just think about that: two months plus six weeks is 3.5 months. That's a broad estimate.
Paul Fremont, Analyst
Okay. But obviously
Tom Fanning, CEO
Hey, excuse me, Paul. We certainly have allowed for more time than that in the revised schedule. Remember, we added three months to all of that.
Paul Fremont, Analyst
Okay. Right.
Tom Fanning, CEO
That's my answer to your question.
Paul Fremont, Analyst
Okay. So you believe you have about six weeks of physical work remaining?
Tom Fanning, CEO
Okay, so in order to get to 103G, there is about six weeks of work left to do.
Drew Evans, CFO
Paul, let me add that we have certainly allowed for more time than that in the revised schedule. Remember, we added three months to all of that. That's my answer to your question. So you believe you have six weeks of physical work still to go? Okay, so in order to get to 103G, there is about six weeks of work left to do.
Paul Fremont, Analyst
And then can you tell us where you are relative to turnover and testing? I think there were 159 systems for each of the plants that need to go through turnover and testing. I think the last update, you were roughly at 120 on Unit 3. But is there any update on where you are now on Unit 3 and Unit 4?
Tom Fanning, CEO
We have now completed all 158 walk-throughs. There are approximately 100,000 hours of direct construction left to complete. We had around 17 systems to start with, and now there are about 11 that we've turned over since the July call. While we are making progress, the timeline might not be as straightforward as it seems since all systems are being worked on concurrently. To achieve 103G, we need to complete eight system turnovers, and there are seven more to complete before we reach fuel load. These seven and the eight necessary for 103G are being worked on simultaneously. After reaching fuel load, there will still be two systems that can be worked on. To summarize, of the 17 remaining systems, eight are needed for 103G, seven for fuel load, and two can continue post-fuel load.
Paul Fremont, Analyst
And then my last question, I'm sorry.
Drew Evans, CFO
Just want to clarify, Paul. In our materials, when it does relate to ITAAC, we provided a schedule of an ITAAC completion cadence that would support an April 103G and May fuel load and September in-service. What you'll note is that there's nothing showing in November because nowhere to support that schedule; we don't need any November. Our expectation is there absolutely will be some in November. In fact, I believe we've already submitted two since the month has begun. So every single ITAAC we file in November that gets completed reduces the number that need to be completed between December and April to support the 103G.
Tom Fanning, CEO
I'm sure you guys know Aaron Abramovitz. He was Chief Financial Officer of the project. He was actually located on-site. Now he's the CFO with Georgia Tower. In order to give you the schedule that you saw in your package, effectively what he did was start with September in-service date. We believe we have margin to that. We believe the margin we established remains consistent, but we wanted to provide you with something to measure our progress. Hitting 103G and ultimately fuel load, we thought was a good way to measure our progress, so look and see how many ITAAC we file in November and December compared to the schedule and I think you'll see that. I think we'll beat the schedule pretty handily, at least early on for sure.
Paul Fremont, Analyst
And then last question, where are you currently in the cost-sharing, Dan, as it relates to you and your partners in the plant? Are you now at a point where you're picking up 100% of the incremental project costs?
Drew Evans, CFO
We believe we have not entered that. We certainly have some discussion among us and the other co-owners about that. I think we've disclosed that and I'd rather not go too far into that and I just appreciate your patience with us there. Just as we don't front-run the regulatory process; as we have a long track record of not doing that, it's best for us to have the resolution of those differences of opinion done in private.
Tom Fanning, CEO
But just very matter of fact, with Paul as we disclosed our calculation to just, we're not even into the first end for sure.
Paul Fremont, Analyst
Great. That's it for me. Thank you so much.
Tom Fanning, CEO
Paul, you're great. Thank you for joining us.
Operator, Operator
Thank you. The next question comes from Sophie Karp with KeyBanc. Please go ahead.
Tom Fanning, CEO
Hello, Sophie, how are you?
Sophie Karp, Analyst
I'm good. Thank you for taking my questions. How are you?
Tom Fanning, CEO
You bet.
Sophie Karp, Analyst
All right. Just a little quick one. Do you expect to have any kind of incremental labor issues as a result of the OSHA rule regarding the COVID vaccination mandate sort of kicks in? Fair to assume, I think and just any thoughts, I appreciate it given your way before this vaccination rates.
Tom Fanning, CEO
Yes, ma'am. We always have the health and safety of our employees foremost in our minds. If you look at the way we've handled the site through the epidemic, I think it's been amazing. The accomplishments that those folks have done even under restricted protocols. We were just on a call here as we just gotten more granularity about what their expectations are. It's 400 pages long. We're kind of diving through it. We know there are legal challenges to come. It's really too early for us to say right now what we think the impacts will be. I know even EEI has requested a 90-day delay. There's a lot to digest right now. Let's keep our eyes on that. Just as a final thought, you folks know that I've been leading the ESCC, the electricity sub-sector coordinating counsel. I know the deals are cyber and physical threats. It also deals with the industry's response to major storms. We call those national response events. I've kind of helped organize the national response to a hurricane or a snowstorm or what have you. Clearly, as you introduce new operating requirements into those gigantic magnitude events, we've got to make sure that we serve the interest of customers, and not only get the wires up and the plants running, but restore hope to the communities we're privileged to serve. We don't want to let any of these new requirements interfere with our ability to serve the American economy during those times. All those conversations are going on right now. I'm very confident by our next earnings call, we'll have more to say there.
Sophie Karp, Analyst
Got it. Thank you for the comments, I appreciate it. That's all for me.
Tom Fanning, CEO
You bet. Thank you.
Operator, Operator
Thank you. Our next question comes from Paul Patterson with Glenrock Associates. Please go ahead.
Tom Fanning, CEO
Hey, Paul. Great to have you with us.
Paul Patterson, Analyst
Hey, guys. Thanks for having me.
Operator, Operator
It appears we're unable to hear you. Please, you will register your question. If you'd like to ask your question. And that will conclude today's question-and-answer session. Sir, are there any closing remarks?
Tom Fanning, CEO
Just to say thank you. I get frustrated at times. I know you guys may get frustrated also, this kind of scheduled stuff. But I think what we're doing right now is conservative and prudent. It gives us more margin. We're working very hard. We're making progress. We'll get there. I want to thank the people at the site for working so hard and making the progress they're making with respect to the challenges of personnel, and quality remain foremost. This phrase we used, get it right, is so important to us, and we will always work to get it right. Thank you for your understanding and all of that. As we move through these issues, we've had good progress. The regulatory constructs that we had on the first $2.1 billion at all, I think was more evidence that we do have a constructive working relationship. The post-Vogtle numbers are essentially irrefutable, I mean, I think that cash flow, earnings trajectory, overall financial integrity of the Company is truly outstanding and we think warrants anyone's interest as an investment. Thank you for your time, and we look forward to talking with you next week at EEI. Dan, any closing comments?
Drew Evans, CFO
No, sir. See everyone at EEI.
Tom Fanning, CEO
All right. That's all, Operator. Thank you very much.
Operator, Operator
Ladies and gentlemen, this concludes the Southern Company third quarter 2021 earnings call. You may now disconnect.