TG Therapeutics Q3 2021 Earnings Call Transcript

Quartr
Provided by Quartr
November 3, 2021

There are 11 speakers on the call.

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 Third Quarter 2021 Earnings Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question and answer session.

Operator

I would now like to turn the call over to Mr. Scott Scanno, Investor Relations Director. Please go ahead, sir.

Speaker 1

Thank you, Myra. Good afternoon, and welcome to Southern Company's Q3 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 This could cause actual results to differ materially from those indicated in the forward looking statements, including those discussed in our Form 10 ks, to Form 10 Qs and subsequent filings.

Speaker 1

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 to this 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 Feeney.

Speaker 2

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 Q3. The economies in our service territories continue to recover from the COVID-nineteen 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.

Speaker 2

Dan will share more on this in a moment. So let's begin with an update on Vogtle Units 34. 2 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, ceded our estimate from July.

Speaker 2

The change in the Unit 3 schedule into the Q3 of 2022 It's primarily a function of the time needed to address the full scope of the remaining remediation work and to account for the impact on productivity resulting from higher than expected attrition and slower than expected on boarding of new electricians, field engineers and supervisors. For Unit 4, Recent progress has slowed as craft labor and support resources have been temporarily shifted to support Unit 3's completion effort. Considering this decrease in available resources over the next several months, plus recent productivity trends, We now expect Unit 4 in service during the Q2 of 2023. Importantly, with the corrective actions the site is implemented after discovery of the Unit 3 quality issues, to the operator, including reinforcement of the importance of first time quality with craft personnel and improvements to the application of Sechtel'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.

Speaker 2

During the Q3, consistent with the surrounding areas, The site experienced a spike in COVID-nineteen cases that approached the peak of cases we experienced early in 2021. While the availability of vaccines and well established protocols help preclude to the same degree of disruption experienced during the 1st waves of COVID-nineteen, the pandemic was certainly a contributing factor to overall activity and resource availability. For Unit 3, repairs to the spent fuel pool, System turnovers and ITAC submittals continued throughout the Q3. Repairs to dispense fuel pool are now complete and the next major milestone for Unit 3 will be the receipt of the 103 gs letter from the NRC. To date, 242 ITAC have been submitted to the NRC with 156 remaining.

Speaker 2

On Slide 7 of today's earnings call deck, we have included a forecast of the remaining ITAC submittals required to support a projected May 2022 fuel load and third quarter to 2022 projected in service date. Now considering our recent volume of ITAK submittals in October And the expected completion and turnover of significant systems in the months ahead, the site is targeting ITAC 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 ITAC 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. Our revised projected in service date of the Q2 2023 reflects to the temporary shift of services to Unit 3, recent productivity trends on bulk electrical work and ongoing effort to add craft labor and non manual field support resources in support of first time quality and productivity.

Speaker 2

Construction completion for Unit 4 has averaged 1.4% per month since the start of the year. To achieve a Q2 2023 in service date, We estimate that 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 $264,000,000 largely driven by our updated schedule, Productivity consistent with recent trends, the cost of additional resources to complete the full score for remaining work with necessary focus on quality and the replenishment of contingency. As a result, Georgia Power recorded an after tax to a charge of $197,000,000 during the Q3. 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.

Speaker 2

Our priority is bringing Vogtle Units 34 safely online to provide Georgia with a reliable carbon free energy resource for the next 60 to 80 years. We are committed to taking the time to get it right to submit remaining ITAC to support receipt of the 103 gs letter prior to fuel load and commercial operations in 2020 to. 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 toward the start of open vessel testing, which is now projected by the Q2 of 2022. Dan, I'll turn the call over now to you for an update on the financials.

Speaker 3

Thanks, Tom, and 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 Q3. For the Q3 of 2021, we reported earnings per share of $1.23 on an adjusted basis, $0.01 higher than both our to our Q3 and our adjusted Q3 2020 earnings per share. For the 9 months ended September 30, 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 in earnings package.

Speaker 3

Major drivers for our adjusted earnings results for the Q3 of 2021 included higher retail kilowatt hour sales at our to state regulated utilities as we continue to see recovery from the pandemic, strong customer growth and impacts of several Structive regulatory outcomes. Partially offsetting these impacts, nonfuel O and M reflects a trend towards more normal operating conditions relative to 2020. Milder than normal summer temperatures in the Southeast also negatively impacted to earnings per share by $0.02 compared to our estimate and by $0.07 compared to the Q3 of 2020. Turning now to customer growth. Through September, we have added over 40,000 new residential electric customers and over 20,000 to residential natural gas customers across our regulated utility.

Speaker 3

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 next year. For the Q3, weather adjusted retail electric sales were up 3% compared to last year and we're 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.

Speaker 3

Absent this customer specific event, industrial sales have been in line with our forecast for the quarter. We continue to analyze retail sales and in aggregate through the Q3, our retail sales have essentially recovered to 2019 pre pandemic We are encouraged by these positive signals, while we also continue to monitor the potential impact of COVID-nineteen variance, to supply chain constraints and labor force participation. The economic development pipeline in Southeast remains robust. Job announcements and business investment in Georgia in the Q3 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 $13,000,000,000 in capital investment in the coming years.

Speaker 3

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 to $3.05 We expect to achieve adjusted full year earnings above the top end of our guidance range of $3.35 per Our estimate for the Q4 is $0.35 per share, which implies an estimated full year result of $3.40 on an adjusted basis. Before turning the call back over to Tom. I'd like to follow-up briefly on Tom's update on Vova 3 and 4. First, I want to reiterate our commitment to credit quality, which which has been constant.

Speaker 3

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 which 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 bondholders alike as we execute our financing plans. And finally, let me briefly highlight the Vogtle Unit 3 rate adjustment stipulation that was unanimously approved by the Georgia Public Service Commission on Tuesday.

Speaker 3

Consistent with the framework the PSC established with their order for the 17th VCM process, This most recent order allows $2,100,000,000 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 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, This was a great affirmation of the constructive Georgia regulatory environment. Tom, I'll now turn the call back over to you. Thanks, Dan.

Speaker 2

Let me wrap up with an update on the Southeastern Energy Exchange Market or SEAM and our fleet transition. Subject to resolution of any rehearing requests, Seam is moving forward after clearing the approval process. Seam is a region wide automated intra Our 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 SEAM members Scores very favorably on all important metrics compared to the RTOs across the country.

Speaker 2

Seam will improve electric service to customers in the Southeast, a reason that is already an industry leader for customer satisfaction and reliability. The members of Siem 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 Seam is good for our customers and we're excited to be a part of this new platform, which is expected to launch in mid-twenty 22. Turning now to our fleet transition. In our most recent climate report Named Implementation and Action Toward Net 0, we reaffirmed our long term goal of achieving net 0 greenhouse gas emissions by 2,050.

Speaker 2

As an important step in the transition of our fleet, earlier this month, Alabama Power and Georgia Power filed plans with their respective to state environmental authorities detailing how each would comply with the United States Environmental Protection Agency's to Fluent Limitation Guideline. With these expected changes and the recent retirement announcement of 2 coal units at Mississippi Power's Plant Daniel. 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 ELG compliance filings, including the exact timing of retirements and any other actions we may recommend remain subject to the approval of our state public service commissions through the Integrated Resource Planning Processes or IRPs.

Speaker 2

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 units. 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 We'll significantly inform our capital investment opportunities. As we always do, We will update our capital investment plans during our Q4 earnings call early next year, which will include known fleet to transition opportunities. It is likely that further transparency on our long term capital plan will unfold throughout to 2022, and we will update our forecast as appropriately.

Speaker 2

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 to our 5% to 7% long term growth range. Now, before we move to the Q and 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 Time, came out with their best for vets ranking of employers. And we've typically been on the list.

Speaker 2

It shows the top 15 companies across America and it Includes well known companies like Bank of America, Booz Allen Hamilton, Hilton Group, Johnson and Johnson and others. They just had named Southern Company the number one company in America That's best for vets. That included evaluations of recruiting practices, retention and support programs and a higher emphasis on employers who provide assistance and flexibility for individuals in the Guard and the Reserves. We certainly respect the contribution that these folks make. They are a significant part of our employment base, I think amounting to over 11% of employees today.

Speaker 2

We respect their service and we want to make sure that they have the best work environment that they could have. 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

Thank Our first question comes from Shahriar Pourreza with Guggenheim. Please go ahead.

Speaker 2

Hello, Shahriar. Thanks for joining. Thanks, sir. Thanks. Excellent.

Speaker 2

Dan, nice to hear your voice.

Speaker 4

Just a couple of quick questions here. Tom, a lot of investors are hoping to hear more about your post Vogtle CapEx opportunities at next week, especially kind of with your Georgia and Alabama IRPs next year. Can you remind us of Some of the types and size of the incremental CapEx we could see when you roll the CapEx plan forward next February. Maybe offer some ballpark figures to help frame the opportunity set as you shut down coal. How you'll finance it?

Speaker 4

What the impact of rates could be? I mean, I understand things will shift between now and then, but any color would be great.

Speaker 2

Yes, Shar. I We're not going to say very much next week. Suffice to say that These plans, if approved by the public service commissions, will have an impact on CapEx. We always provide that update in our call. I guess it will be the end of January or early February about our Q4 results and total year results.

Speaker 2

So we will certainly do that then. But I think, as I said, To the extent there are impacts, the current capital forecast formulated a range in 20.22 of $4 to $4.30 To the extent there is an increase in CapEx, certainly that strengthens our placed within that range and the longer term 5% to 7% growth rate. The other thing that we should remember about rates is That as you retire coal, you free up a whole lot of O and M. We intend to use that O and 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

Speaker 3

And, Shar, just a reminder, what Tom said in his prepared remarks is the $4 to $4.30 On 2024 is predicated on our current CapEx plan. And I think the way to think about these incremental opportunities is They will potentially increase or intensify over time. I mean, you kind of said post Vogtle, I think that is the point in time when we really begin to see tangible long term increases to that profile from $8,000,000,000 a year to something more.

Speaker 2

And one last Point there. One of the benefits of our integrated resource planning process is we get to optimize portfolios Not only on generation, but also transmission. So transmission could be a benefit there. The other one you should keep in mind is we currently we said this on other calls, we currently allow for about $500,000,000 a year of cap allocation to things like Southern Power. None of those Allocations are included in our forecast and it would stand to reason that as the United States Transitions its generating fleet, there will be more opportunities for Southern Power in that regard.

Speaker 2

And just on the transmission chart

Speaker 3

And the reason we're being a little hesitant to share too early, while there's transmission opportunities associated with what we will retire, The other transmission opportunities come about with what we replaced that with and where, and that is simply a function of our integrated planning processes and we just need to let those play out.

Speaker 2

But it's a good thing for us, good thing for our customers, we get to iterate around those choices. You don't get that opportunity in the organized markets.

Speaker 4

Got it. Thank you for that. And I know, lastly for me, I know there's a lot of focus on exactly which month Unit 3 will be in service next year. But I'm a little bit more interested on what happens once it's online. So once Unit 3 comes online, how should we think about what that means for earnings and cash flows in light of the PSC approving the joint settlement I know there's a lot of moving parts with the NCCR, the AFUDC, the penalty ROEs, but just really at a high level, What are sort of the immediate impacts to cash flows and earnings following Unit 3 reaching in service?

Speaker 4

Thanks guys.

Speaker 3

Yes, absolutely. So let's just make the assumption for the sake of describing all this, Shar, that the Q3 means September of 2022. So given the result of the Georgia Public Service Commission earlier this week, that will mean that Rates will go into place for $2,100,000,000 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 a 3rd of a cent of EPS for every month. So for October, November December relative to what you would have forecasted under Current conditions, it's about a $0.03 per month.

Speaker 3

The important thing is that $2,100,000,000 is not the full cost of Unit 3 in the common facilities, all what remains will remain earning a return under NCCR Or we'll be deferred for future recovery with the commission. And at the same time, we'll be recovering Currently, the operating cost of Unit 3 and the depreciation at least associated with the $2,100,000,000

Speaker 4

Got it. That was super helpful. Thanks guys. I appreciate it. Great execution.

Speaker 2

Thanks, John. Thank you.

Operator

Thank you. Our next question comes from Julien Dumoulin Smith with Bank of America. Please go ahead.

Speaker 2

Hey, Julian. How are you?

Speaker 5

Hey, quite well. Thanks, Tom. It was a pleasure to connect with the team. Congrats, Dan, too. So, let's just dive right in on the asset sale front here.

Speaker 5

You obviously made some pretty interesting comments a moment ago. Just wanted to clarify there what As you think about regulated versus perhaps some of the other assets you own that Southern Power or otherwise, what exactly are you thinking about there? And then more importantly, What equity need are you kind of thinking about here? Obviously, it's not it doesn't seem at least as explicitly stated too substantive here. But can you talk about how you're Thinking about equity needs, especially considering some of the prospective CapEx you alluded to, I suspect that kind of feeds into this commentary on asset sales too.

Speaker 2

Yes, sure. I'll let Dan speak to the equity needs. I'll go back to the kind of litany on M and 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.

Speaker 2

And so We have ideas right now. 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 kind of are looking over our list of things and we'll see.

Speaker 2

Dan, you want to speak to the equity needs?

Speaker 3

Yes, absolutely. So Julien, essentially what we're addressing is only the impact of the recent Vogtle cost increase. So to the extent that 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 and our credit metrics out there Are about 200 basis points for FFO to debt higher than they are today, and that's a position of strength for us and gives us a lot of flexibility as to how we finance our growth.

Speaker 3

And hey, I just want to clarify just back on Charles' question. I said a third of a cent per month. It's 2 thirds of cent per month. Want to make sure that's clear.

Speaker 2

Two thirds of Central. Yes. Got it. Yes. And to be very clear too, I'm trying to be less elliptical on kind of what we're looking at.

Speaker 2

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 or sell things which make ourselves more risky. I think we love the idea of reasonable turn and low risk. And also, as you have seen in the past years or so 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.

Speaker 6

Got it. Excellent.

Speaker 5

And then just coming back to Unit 4, obviously, you made some comments a moment ago about some of the labor availability, etcetera, And remediation work, I mean, how do you feel comfortable with the 9 month time gap between those 2 units in service dates, right? And I'm just calling out that Staff has stated at some of the various points about some of the concerns they have on that the second unit in service.

Speaker 2

Yes, Julien, yes, thanks for that. It's an important point to raise as the tides have both ebbed and flowed here. Let me explain that a little bit. We believe that Bechtel has had the responsibility to attract skilled personnel, skilled craft work, especially electricians, 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 name the reason why We've had more attrition.

Speaker 2

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're moving to de link the progress at Unit 4 from Unit 3. And so therefore, this 12 month kind of margin didn't matter. One of the ways that we serve to continue to advance Unit 3 was again to borrow personnel from Unit 4.

Speaker 2

So 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 and once again they will be delinked. 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. And so that has happened. The other thing that we have done is to augment Bechtel's sourcing efforts with our own We've had a very deep engineering and construction services group in Birmingham, our own resources that we could attract personnel.

Speaker 2

And so 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. And I will say one more thing. There was a lot of conversation about this.

Speaker 2

I can tell you Chris Womack and I in particular were really watching the trends. If I just looked at current data, We still have margin, 6 weeks or so to Unit 3, 3 months or so to Unit 4 on the existing not extended schedules. We looked at the trends, however, and the trends to me were troubling. And so we all kind of step 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 6 months of scheduled margin left on 3 and 3 months of scheduled margin left on 4. And we could have quibbled on adding a month or 2 months.

Speaker 2

We said, let's go ahead and add a quarter for both. And that's where we came out on this decision.

Speaker 5

Got it. So it's not so much The 9 months necessarily, it's that you're adding a quarter on both and there's latitude within both schedules, if I'm hearing you right.

Speaker 2

Yes. And this idea of there's got to be 12 months, they are in fact the only time they're 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're able to send the people back to 4, and again, they are delinked. The 9 month difference between the two does not trouble us.

Operator

Thank you. Our next question comes from Steve Fleishman with Wolfe Research. Please go ahead.

Speaker 2

Great. Thank you. Glad to have you with

Speaker 6

us. Likewise. Dan, Nice to have you CFO. So just first on the maybe Tom just on the Vogel schedule. I know you don't want to speak for staff, the commission, but just With this latest update in the way that you're kind of giving schedules now, is it is there a better chance That they'll match up closer to what you're saying when they come out in a few weeks on this?

Speaker 6

Or should we be prepared for something that's again different than what you're saying?

Speaker 2

Yes. Steve, you kind of gave me the answer before I answered and that is I don't want to speak for Doctor. Jacobs is a guy that I know well. He attends the same meetings we Tandy sees the same stuff we see. He's a really bright guy.

Speaker 2

I think if I had Highlight something that will come under some discussion and I think it's absolutely correct. You want to look at schedule kind of variability at this point. We believe we see a Pretty clear track to receiving the 103 gs letter, which allows us to load nuclear fuel, 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 that is from 103 gs receipt To loading the fuel is probably the remaining biggest risk to schedule that remains on Unit 3.

Speaker 2

Recall in the script, we talked about finding more remediation. And I know in some other media, we've talked about these items, none of them being deal killers and all that stuff. There's no such thing as a little issue in nuclear. Everything we take seriously, everything must be done effectively with perfection. And so it is that time that we're looking at right now that I would say to you It's probably the shared view of Doctor.

Speaker 2

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 gs 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 6 weeks of work left from receipt of the letter to the actual loading of the fuel. If the 103 gs letter is delayed, Then that 6 weeks reduces because this is work that can be done in parallel with some of the other stuff That's required to get 103 gs. Remember, we've talked about 3 buckets of work that We identified post HFC. One bucket deals with the issues we identified during to the test.

Speaker 2

The second deals with remediation that frankly has increased since we passed the 103 gs letter And really with subsequent to the July call we had with you guys. The last bucket really dealt with human performance So that work margin is bigger. So let me just say it again. If we get receipt of 103 gs kind of early, let's say it's January, I mean who knows, It could be as much as 6 weeks. If we get 103 gs later, that work time will shrink to 2 weeks or something.

Speaker 2

We'll see. See, that's where I think you will see a lot of discussion between us and the commission.

Speaker 6

And if

Speaker 3

I could just add real quickly to Tom's comments, the nature of the risk for that will work post 103 gs up to fuel load It's really logistics. So once we receive 103 gs, the site becomes an operating nuclear site. So The logistics of getting people the ingress and egress of personnel to do the remaining work is just friction on productivity and that's really the nature of that risk.

Speaker 6

Great. Thank you. That was helpful. Yes, that was very helpful. And Dan, going back to the question before about trying to kind of size the Potential equity need or asset sale target need.

Speaker 6

You said just look at the what the cost increases have been. Is that It's as simple as that or are you targeting any different metrics as well than you had prior to that.

Speaker 3

Yes. Look, Steve, we're 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, I mean, we are looking across multiple opportunities. We will see what that looks like. More importantly, From a long term perspective, that uplift in the credit metrics that we've talked about is really what is key.

Speaker 3

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 more significant than those near term Kind of charges that we've taken to Darren.

Speaker 6

Okay. And you haven't

Speaker 2

Go ahead, Steven. Go ahead.

Speaker 6

Yes. No, I'm just you haven't given a number on what the DRIP equity that you said you turned the DRIP on.

Speaker 2

Did you Thank you, Ali. We have

Speaker 3

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 $400,000,000 Worth of equity.

Speaker 2

Yes.

Speaker 6

Okay.

Speaker 2

And in a prior call, we kind of said was we thought the DRIP in 1 year would solve The last issue, this is another roughly $200,000,000 So 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.

Speaker 6

Okay.

Speaker 2

So please assure, If we can find a better solution than issuing shares under the DRIP, we'll do it.

Speaker 6

Right. And I guess to the degree that there might be some Incremental growth opportunities in the capital plan as you go through IRPs, fleet transition, etcetera, Asset sales could help fund that part too.

Speaker 2

Sure they could. And as Dan indicated, Rob, if you look at the CapEx forecast, most likely the CapEx opportunity associated with the transition of the fleet We'll look to run the back part of that CapEx forecast.

Speaker 6

Okay. That's right. Where our

Speaker 3

credit metrics will be much higher than we are. Okay.

Speaker 2

Thank you. Thank you, Steve.

Operator

Thank you. Our next question comes from Jeremy Tonet with JPMorgan. Please go ahead.

Speaker 2

Hey, Jeremy. How are you?

Speaker 7

Good, good. Thanks for having me. Just want to come back to Vogtle, if I could here. Just want to see if you could provide some And some color on labor market impacts here. And just as I'm thinking, how much does cost go up per month delayed at this point?

Speaker 7

Just this Prior increase seemed a bit larger than I would have thought.

Speaker 3

Yes. So Jeremy, the way to think about it, this has really been what has occurred both in the Q2 and this most recent announcement here in the Q3. The cost increases have really been a function of 2 things. 1 is the schedule itself. And so that's kind of that notion of hotel load that we talk about, right?

Speaker 3

And so for Unit 3, that is $35,000,000 a month, I believe, for Unit 4 for our $25,000,000 a month and about $15,000,000 a month for Unit 4. So for every month for each unit, that's just The infrastructure that supports construction and the cost of that. With this most recent increase and again, much like to the 2nd 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.

Speaker 3

Both increases really represented about half Pure schedule or hotel cost is in the other half, personnel and productivity assumptions to complete the work.

Speaker 2

Yes. And I would be remiss if we didn't add the idea that in sourcing all of these personnel and the skilled labor, Sean McGarvey and his team at the Building Trades has been fabulous. The IBEW in particular has been great. They've given us tremendous ongoing support, and I think our relationship with them is really bearing fruit here as we augment Bechtel's efforts.

Speaker 7

Got it. That's helpful. Thank you for that. And maybe just pivoting towards DC for a minute here, if I could. Obviously, things are fluid here.

Speaker 7

But just wanted to see, as things stand right now, what are your biggest takeaways from the federal infrastructure legislation? And when thinking about minimum tax as well, I guess, how do you think of some of the gives and takes as it relates to Southern?

Speaker 2

Yes. Jeremy, calling the situation in Washington fluid is a bit like calling the Grand Canyon a crack. I will say this, that there's lots of good stuff in the infrastructure bill and in the reconciliation bill that help us. They're shaped mostly as incentives and we think that incentives are the way to go. We're particularly Good in anything that as we go through this transition of the fleet and transmission to a net zero future that we prices as low as possible to help our energy resource in a worldwide competitive market to keep it To keep America in a very strong position to compete for new loads and manufacturing and a variety of other things.

Speaker 2

So It is important for the nation. It is important for our customers to keep prices low and to provide incentives to do that. That's kind of thing 1. Same to. Dan can correct me here or whatever, but we've looked at this minimum tax proposal And we think it doesn't have that much of an impact to us.

Speaker 2

Maybe it bounces around from year to year as you would expect, but it kind of averages 1%. That's right, Tim. So, it doesn't have much of an impact to us. I'm sure it would for others that rely on tax benefits to drive their earnings.

Operator

Thank you. Our next question comes from Michael Lapides with Goldman Sachs. Please go ahead.

Speaker 2

Hey, guys. Hey, Michael. Go ahead, Mike.

Speaker 8

I just want to say, A, thank you for taking the Dan, congratulations, another kind of really talented person in the CFO seat and a large Company always with lots going on and kudos, well deserved.

Speaker 3

Thanks, Michael.

Speaker 8

Next year in Georgia, And I'm just trying to think about the regulatory calendar and the series of events and more how they intertwine or if they intertwine. So you'll go through the IRP process. I forget if the IRP actually gets kind of formal approval or not. But you also, I think, still have a rate case. And then

Speaker 4

will you also file to

Speaker 8

get Unit 4 in service if it looks like similar to how with Unit 3 to go ahead and set what the revenue requirement would be.

Speaker 2

Yes. 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 of the Georgia Power Company with its relationship with the PSC itself and with the workload at the staff. I think we've always managed to find our way to get big things done.

Speaker 2

And 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 relationship. There is a lot going on next year with VCM, with IRP, with Vogtle 3 with potential prudence hearings beginning on the fuel load of 4 with a rate case filing. So there's a lot to work through. Just understand that as we have in the past, we'll work with the folks involved to do it in the right way.

Speaker 9

Got it. My other question And

Speaker 8

I saw a little news blurb brief this past week or so about your buying a plant from a 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 and A to bring them into rate base versus going through the construction process?

Speaker 2

Yes, We do. And 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 said this in the past, to get to net 0 for us, we're going to have a profile in the 2,040 to 2,050 that We'll look something like 50% renewables, maybe 20% nuclear, maybe 25% natural gas.

Speaker 2

A lot of that natural gas will have CCS on it. The kind of 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.

Speaker 2

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 '50s. But anyway, my sense is that you're going to have A lot of opportunity to buy some natural gas. The good thing about buying used units is then they have a remaining life of 10 to 15 years. That fits in with retirement schedules that are consistent with adding more renewables.

Speaker 2

So those assets look like bridging And very attractive economically and important to our strategy of replacing it with renewables.

Speaker 8

Got it. Thank you, Tom. Much appreciated.

Speaker 2

You bet. Always good talking with you.

Operator

Thank you. Our next question comes from Paul Fremont with Mizuho. Please go ahead.

Speaker 2

Hey, Paul. It was a pleasure to have you with us. Yes, sir.

Speaker 9

Thank you so much. You've talked a little bit about That you still have construction work remaining on the plant. Can you give us sort of a timeframe that it's going to take For you to complete the construction and if you want to sort of separate out that 3rd bucket that you think you can do After you get the letter, you can do it either with or without that bucket.

Speaker 2

Paul, maybe I'm not following your question. Could you try that again?

Speaker 9

In terms of days or months, How much physical construction work do you have yet remaining on Unit 3?

Speaker 2

Okay. So In general, what I indicated was here we are in Nearly the middle of November, okay. So in order to hit January 103 gs, So that's 2 months, round numbers, okay? And then I would say if we had 103 gs in hand in January, My best guess right now is there may be another 6 weeks of construction. So let's just think about that 2 months plus 6 weeks is 3.5 months, Okay.

Speaker 2

That's a broad estimate.

Speaker 9

Okay. But obviously

Speaker 2

Hey, excuse me, Paul. And we certainly have allowed more time than that in the revised schedule. Remember, we added 3 months to all that. Okay. That's my answer to your question.

Speaker 9

Okay. So you believe you have 6 weeks of physical work still to go. And then Well,

Speaker 2

wait, wait, hold on, hold on, Paul. It's what I would say is 6 weeks of physical work To get to 103 gs, it may be that it takes 8 weeks. I mean, who knows? But that's just a reasonable guess. So middle of November no, I'm sorry, wait a minute, I said 2 months.

Speaker 2

Middle of November to middle of January is 2 months. And then you would say add on some more time to get to fuel load, right? That was the response to, I think it was Fleischmann. So between 103 gs and fuel load, There is more work to be done and I estimated that at its maximum, say 6 weeks and then at the minimum, that's assuming we have a delay on 103 gs of 2 weeks, something like that. So say, what did I say, 3 or 4 months?

Speaker 2

Am I answering your question there? Yes. I think 2 weeks, Tahpal, let me

Speaker 9

2 months plus another either 6 weeks or 3 weeks depending on where you are If

Speaker 2

it was less than 6 weeks. Yes, but Paul, remember, As I said, if it was less than 6 weeks, that presumes that there is a delay in getting 103 gs. The total amount of time is, let's just say, 3 to 4 months.

Speaker 3

Yes. And Paul, just stated a different way with our September assumption for in service the Q3 of 2022, then work could continue Through April with a 103 gs receipt, fuel load in May and then in service in Septon.

Speaker 9

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 that need to go through turnover and testing. You were I think the last update, you were roughly at 120 on Unit 3. But is there any State on where you are now on Unit 3 and Unit 4?

Speaker 2

So let's think about it. We have now completed so there was 158 walk throughs to go through. We've completed them all now. Okay. So let's start there.

Speaker 2

We think there's about, let's see, 100000 hours or so of Direct Construction. We have in terms of systems, I forget how many we started with, but around 17 left to go. In between the July call and now, we turned over 11. And so what's kind of interesting to look at is the symmetry of that, even though I think we're probably closer. If in 3 months, We turned over 11.17 to go, I just said 3 to 4 months.

Speaker 2

That's a little inaccurate because All the systems are being worked on and we're getting closer to complete all the systems. So, there's probably a little bit less than that. In order to get to 103 gs, we need the completion of 8 system turnovers. We have 7 to get to fuel load. So that's the delta between 103 gs and fuel load.

Speaker 2

And I said that can expand and contract how we think about that. Those 7 are being done in parallel with The 8 required to get 103 gs. So those are not sequential, they are parallel. And then even after fuel load, there are some Thanks. That will continue to be worked on.

Speaker 2

I think there's like 2 systems that you can do even after fuel load. So let me just say that again. Of the 17 systems that remain to turn over, 8 Are required to get 103 gs 7 are required to get to fuel load 2 Can be continued to be worked on even after fuel load.

Speaker 9

So I'm gathering from what you're saying. In the past, I think you've needed to get all of your ITACs approved by the NRC before you could get the 103 gs letter. I'm gathering here, are you guys asking for the NRC to give you different treatment where you would get the 103 gs letter before all of

Speaker 2

No, no. This is all consistent with everything we've ever done with the NRC and 103 gs. Everything is considered.

Speaker 9

In other words, all the ITACs would need to be approved, but I would assume that not all the but you would still have systems that would be untested. So those are systems that don't require ITAC approvals, I take it?

Speaker 2

Yes. In order to get permission to load fuel. So the systems after permission to load fuel are not necessarily safety related items. There could be some of these signage issues or something like that. Anything that is required to get 103 gs is encapsulated in the 8 systems I mentioned.

Speaker 2

Before we load fuel, we still want to do 7. 2 of those not 2 of those, an additional 2 can be done even after we load fuel. They're just not safety related construction items.

Speaker 9

And then my last question oh, sorry.

Speaker 3

Yes. Just want to clarify, Paul, in our materials, when it does relate to ITACs, We provided a schedule of an ITAC completion cadence that would support the April 103 gs May fuel load September in service. What you'll note is that there's nothing showing in November because in order to support that schedule, You don't need any November. Our expectation is there absolutely will be some in November. In fact, I believe we've already submitted 2 since the month has begun.

Speaker 3

So everyone in November that gets completed reduces the number that need to be completed between December April to SPORT 103 gs.

Speaker 2

And I'm sure you guys know Aaron Abramowitz. He was kind of the Chief Financial Officer of the project. He was actually located on-site. Now he's the CFO of Georgia Power. In order to give you the schedule that you saw in your package, Effectively what he did, he started with a September in service date.

Speaker 2

We believe we have margin to that. But he started with September in service And then he reverse engineered back in a conservative way to say, well, this would be the ITAC completion schedule consistent with Timber. We believe we have margin to that. As we get ITACs filed in November, I'll go ahead and say we expect to get about 20. Well, this one the schedule we gave you indicates nothing in November and not much work in December.

Speaker 2

We think we'll have that Exceeded by a pretty good margin. And so we'll be ahead of the schedule. Well, that just suggests our belief that in fact there is margin to the schedule we're giving you now. And the other thing that was important in this, the reason why we went to all this trouble We thought you guys would want to have a way to measure our progress in hitting 103 gs and ultimately fuel load, and we thought this was kind of a good way to measure our progress. So look and see how many IFAKs we file in November December and And compare to this schedule and I think you'll see that I think we'll beat this schedule pretty handily at least early on for sure.

Speaker 9

And then last question, where are you currently in the cost sharing band 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

Speaker 2

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 Just as we don't front run regulatory processes, we have a long track record of not doing that.

Speaker 2

It's best for us to have the resolution of those differences of opinion done in private.

Speaker 3

Yes. Just very matter of factly, Paul, as we disclosed, Our calculations suggest we're not even into the first band of sharing.

Operator

Thank you. The next question comes from Sophie Karp with KeyBanc. Please go ahead.

Speaker 2

Hello, Sophie. How are you?

Speaker 9

I'm doing well.

Speaker 10

Thank you for taking my questions. How are you?

Speaker 2

You bet.

Operator

All right. So

Speaker 10

Just a real quick one. Do you expect to have any kind of incremental labor issues as a result of the Hello, Charu, regarding the COVID vaccination mandate sort of kicks in fairly soon, I think. And just any thoughts, I appreciate to Europe. Can we before its vaccination rate?

Speaker 2

Yes, ma'am. We always Have the health and safety of our employees foremost in our minds. And I think if you look at the way we've handled the tight through the epidemic. I think it's been amazing, the accomplishments that those folks have done even under restrictive protocols. We were just on a call here as we've just gotten more granularity, I guess, from OSHA about what their expectations are.

Speaker 2

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. So I know even EEI has requested a 90 day delay.

Speaker 2

Look, there's a lot to digest right now. Let's keep our eyes on that. And just as a final thought, you folks know that I've been leading the to the SEC, the Electricity Subsector Coordinating Council. I know that deals with cyber and physical threats, it also deals with the industry's response To major storms, we call those national response events. And so I've kind of helped organize the national No response to a hurricane or a snowstorm or what have you.

Speaker 2

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 Any of these new requirements interfere with our ability to really serve the American economy during those times. So all of those conversations are going on right now. And Sophie, I wish I could give you more granular stuff, but it's all Yes, very timely conversation we're working through. I'm very confident by our next earnings call, we'll have more to say there.

Operator

Thank you for the comments. Appreciate it. That's all for me.

Speaker 2

You bet. Thank you.

Operator

Thank you. Our next question comes from Paul Patterson with Glenrock Associates. Please go ahead.

Speaker 2

Hey, Paul, great to have you with us. Paul? Well, it's still great to have you with us. I don't know where he is.

Operator

Mr. Patterson, your line is open. Please check your mute button or lift your handset. It appears we're unable to hear you. And that will conclude today's question and answer session.

Operator

Sir, are there any closing remarks?

Speaker 2

Just to say thank you. I get frustrated at times. I know you guys may get frustrated also this kind of schedule stuff. But I think what we're doing right now is conservative and prudent. It gives us more margin.

Speaker 2

We're working very hard. We're making progress. We'll get there. And 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, quality, that always remains foremost. And this phrase we use, get it right, is so important to us.

Speaker 2

We will always work to get it right. So thank you for your understanding and all of that. As we move through these issues, we've had good progress. The regulatory construct we had on the first $2,100,000,000 et al. I think it was more evident that I think we do have a constructive working relationship.

Speaker 2

And that post Vogtle, the 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. So thank you for your time and we look forward to talking with you next week at EEI. Dan, any closing comments? No, sir.

Speaker 2

See everyone at ease. All right. That's all, operator. Thank you very much.

Operator

Thank you, sir. Ladies and gentlemen, this concludes The Southern Company Third Quarter 2021 Earnings Call. You may now

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TG Therapeutics Q3 2021
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