Southern Co (SOMN) 2018 Q2 法說會逐字稿

Good morning. My name is Melody, and I will be your conference operator today. At this time, I would like to welcome, everyone, to the Southern Company Second Quarter 2018 Earnings Call. (Operator Instructions) As a reminder, this conference is being recorded today, Wednesday, August 8, 2018.

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

Thank you, Melody. Good morning. Welcome to Southern Company Second Quarter 2018 Earnings Call. Joining me this morning are Tom Fanning, Chairman, President and Chief Executive Officer of Southern Company; and Drew Evans, 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 the Form 10-K, second quarter 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 the conference call. The slides we will discuss during this morning's call may be viewed on our Investor Relations website at investor.southerncompany.com.

At this point, I'll turn the call over to Tom Fanning.

Good morning, and thank you for joining us today. Drew and I will cover our usual business updates in a few moments, but first, we'd like to provide an update on Vogtle 3 and 4.

Reflected in our reported earnings for the second quarter is a $1.1 billion pretax charge, which represents an increase in Georgia Power's share of the projected cost to complete Vogtle 3 and 4. We continue to project construction completion dates of November 2021 and November 2022 for Unit 3 and 4 respectively. And the new cost estimate does not reflect any changes in the project schedule.

After Westinghouse filed for bankruptcy in March 2017, part of Southern Nuclear's new self-perform role, was to develop a new cost estimate for completion of the project, as Georgia Power and the other owners no longer had the benefit of a fixed and firm EPC contract with its original contractor.

This is the first time that Southern Nuclear had broad access to Westinghouse's more detailed cost information, invoices, subcontracts and planning and schedule documents, including the basis of estimates being discussed between Fluor and Westinghouse.

Southern Nuclear began building what became the VCM 17 estimate to complete or ETC based on data and information obtained from Westinghouse and Fluor, as assessed by Southern Nuclear and independently reviewed by its consultants.

As a reminder, Georgia Power submit semiannual Vogtle Construction Monitoring Reports or VCMs to the Georgia Public Service Commission.

These filings and the hearings which follow, are an important part of the regulatory framework for the project. The 17th VCM filing on August 2017 was used by the PSC to make its post-Westinghouse bankruptcy go or no-go decision for Vogtle 3 and 4.

As with any forecast, the VCM 17 ETC was based heavily on assumptions regarding scope of work, labor productivity and cost escalation.

The VCM 17 report also included discussions of project risks, including an acknowledgment that work was still ongoing on key terms that could impact costs that the craft labor force may be unable to maintain their productivity improvements and that some scope may be unidentified at the time of the ETC.

Recognizing the potential for cost increases relating to the transition of the project, Southern Nuclear added cost escalation in the form of contingency to the estimate. This contingency was intended to cover costs expected to be specifically allocable within a reasonably short period of time.

Georgia Power submitted the VCM 17 ETC to the Georgia Public Service Commission on August 31, 2017. In addition, Georgia Power provided the PSC with independent estimates of the cost to complete, which were in general agreement with the Southern Nuclear ETC.

Following an exhaustive review of the VCM 17 report, the PSC, in December of 2017, approved Georgia Power's recommendation to continue construction, the proposed new project structure and $7.3 billion as a reasonable total cost for Georgia Power share of completing the project.

This cost reflected Southern Nuclear's initial ETC, net of the $1.7 billion Toshiba parent guarantee and partial customer refunds of that guarantee.

In the years since completing the initial ETC, Southern Nuclear has been able to maintain project momentum consistent with the schedule approved by the PSC.

Although the PSC recognize that the $7.3 billion revised capital cost forecast was not a cost cap, Southern Nuclear undertook efforts to manage the project within that forecast, while at the same time sustaining project momentum and transitioning project management.

In connection with this effort, Southern Nuclear determined that it needed to implement changes at the project to lower project risks and maintain its schedule.

Among others, these changes included expanding the scope of Bechtel's contractor duties and resulting fees, increasing field supervision and engineering support and implementing craft labor incentives to attract and retain adequate staffing.

The project team has also continued its efforts to firm up other estimated costs such as the 60-plus subcontracts that had not yet been negotiated at the time of the initial ETC. Many of these new subcontracts reflect changes in market conditions, and in some cases, increased scope.

As part of the process to continually review and assess cost and schedule, and based on a year's worth of experience managing the project, Southern Nuclear recently revised its estimate of the cost to complete the project. Based on this latest estimate, we now recognize the previous contingency with insufficient to fully offset forecasted cost increases. The new estimate reflects that Georgia Power's projected share of total cost has increased from $7.3 billion to $8.4 billion, an increase of $1.1 billion. This increase includes a base capital cost increase of approximately $700 million and a new construction contingency estimate of approximately $400 million.

We will continue to monitor and evaluate costs associated with construction of Vogtle 3 and 4 and provide updates on our estimate as appropriate.

Although we believe the increased projected costs are reasonable and necessary to complete the project, we have made the judgment that is in the best long-term interests of investors, customers and other stakeholders that we not disrupt project momentum by seeking approval of the based capital cost increase so soon after receiving PSC approval to continue with the project.

Therefore, when Georgia Power files the increased cost estimate with the PSC as part of VCM 19 later this month, Georgia Power will not request recovery of the $700 million in base capital cost increase and precluding these costs from increasing customer rates. Therefore, the customer impacts contemplated in VCM 17 remain the same in VCM 19.

As to the contingency included in our revised capital cost estimate, which is approximately 35% of the total increase, Georgia Power may request the Georgia PSC to evaluate such cost for rate recovery as and when appropriate.

We are hopeful that this revised ETC, a new contingency, will be sufficient to take Vogtle 3 and 4 to project -- to completion. That said, we recognize that a nuclear construction project can continue to experience challenges and that unanticipated events may require further revision to the forecast and project schedule to get to completion.

Meanwhile, progress on construction continues. Several major milestones have been met and we achieved schedule completion dates. And we continue to project in-service dates by November 2021 and November 2022 for Units 3 and 4 respectively.

Our primary construction contractor, Bechtel, continues to plan work based on a schedule months ahead of these dates. We will continue to monitor and evaluate productivity rates and attracting, onboarding and retaining electricians and pipefitters continue to be priorities. We are having success with these initiatives, but we have more work to do.

Additionally, both Southern Nuclear and Westinghouse personnel continue to learn from the now 4 AP1000 units in China, which have loaded fuel and are currently in [state of phase].

I'll now ask Drew to provide a few details on the financial aspects of the new project estimate.

Thanks, Tom. The $1.1 billion pretax charge recorded for Georgia Power, which translates to a $790 million aftertax charge, is an estimate of the increase in future cash expenditures for the project. However, in recognition of our commitment to the credit quality of both Georgia Power and Southern Company, we plan to issue approximately $800 million in incremental common equity through the remainder of 2018.

Likewise, Southern Company will contribute this equity down to Georgia Power to maintain its target capital structure and credit profile, consistent with the Georgia PSC's tax reform order earlier this year. This incremental equity is expected to come from the types of sources that we've used in the past.

While our future financing activities are subject to market conditions and other factors, our current financing plan does not assume any discrete equity offerings or block sales. All else being equal, we project these additional shares to equate to approximately $0.02 of EPS dilution in 2019 and to reach approximately $0.05 by 2020 or 2021 as the project spends and the estimated increase cost to complete are included to complete the project.

Even with these efforts, we do not anticipate any change to our 4% to 6% long-term EPS growth rate guidance. We expect to continue evaluating opportunities to offset these effects and optimize our overall financial plan, including additional investor-friendly sources of funds.

I will now turn the call back to Tom for a brief update on recent initiatives.

Thanks, Drew. In May, we completed the sale of a 33% minority interest stake in Southern Power solar portfolio, and we completed the sale of Pivotal Home Solutions in June.

In July, we closed the sales of Elizabethtown Gas, Elkton Gas and Florida City Gas. Cumulatively, these transactions accounted for more than $3.7 billion in proceeds.

We have completed the appropriate FERC filings for the sales of Gulf Power and Southern Power's plants, Stanton and Oleander. These regulatory approvals are expected to drive the timing for closing on these transactions. Our current expectation is that both transactions will close during the first half of 2019.

We're also making great progress on third-party tax equity financing for the vast majority of Southern Power's existing wind portfolio, which we expect to produce more than $1 billion in proceeds. We hope to close this transaction during the fourth quarter of 2018.

Southern Company has demonstrated tremendous discipline as both a buyer and seller of assets. The AGL Resources and Southern Natural Gas transactions, for example, have proved to be terrific complements to our portfolio of companies, further strengthening our expected long-term growth profile.

Likewise, our recent divestitures have proven to be an effective source of equity with a significantly lower cost of capital than new common shares. Southern will continue this disciplined approach as we seek to further improve upon our state regulated, utility-centric growth profile.

And as a final note, yesterday, the Mississippi Public Service Commission approved the settlement for Mississippi Power company's PEP filing receiving the majority of the requested amount.

Drew will now provide some specifics on our second quarter earnings performance.

Thanks, Tom. For the second quarter of 2018, we reported a loss of $154 million or $0.15 a share. This compares with a loss of $1.38 billion or $1.38 per share in the second quarter of 2017.

For the 6 months ended June 30, 2018, we reported earnings of $784 million or $0.77 per share, compared with a loss of $723 million or $0.73 a share for the same period in 2017.

Excluding charges associated with Vogtle, Kemper and other items described in our earnings material, earnings for the second quarter of 2018 and the 6-month period ended June 30, 2018, were $0.80 and $1.69 per share respectively. These results compare with $0.73 and $1.39 per share on an adjusted basis for the same period since 2017.

Major year-over-year earnings drivers for our adjusted second quarter 2018 results include the positive effects of constructive regulatory outcomes and weather at our state-regulated utilities and increased contributions from Southern Power's renewables fleet. These impacts were partially offset by increased depreciation and amortization as well as operations and maintenance costs.

Before turning the call back over to Tom, I want to provide our outlook for the remainder of 2018. Historically, we have not provided updates to our year-end EPS guidance until we report third quarter results. In light of our performance year-to-date, which is tracking ahead of our plans on an adjusted basis, and the impacts of reducing our new equity needs with the Florida asset transactions, we're updating our adjusted EPS guidance for the full year 2018 to $2.95 to $3.05.

Finally, our estimate for the third quarter adjusted EPS is $1.05.

Tom, I'll now turn the call back over to you for closing remarks.

Thanks, Drew. Once again, I want to thank, everyone, for being with us this morning. I'm sure you all have many questions regarding the topics we have addressed on today's call. So let's go ahead and open the floor for questions. Operator, let's take the first question.

(Operator Instructions) Our first question comes from the line of Jonathan Arnold with Deutsche Bank.

Just one thing I noticed in the disclosure in the 10-Q around Vogtle was that you need to have a new vote of the co-owners, which needs to come in at 90%. It's -- can you just talk to us, Tom, about your -- how confident you are around that process? And what would happen in the event that one of them didn't come along?

Yes. Sure. I have to be very careful not to speak for our co-owners here. There is a governance process that these events trigger that we refer to in the disclosure. Jonathan, the only kind of characterization I can offer, because I want to let their own governance processes speak for themselves, is to say I think that we've had real-time communication with our co-owners and certainly in the past they have been supportive and constructive in our relationship. Beyond that, I really would prefer to let their own process speak for itself.

And what's the timing on when you think that will play out?

Yes. Certainly, it will be at the very end of the third quarter, perhaps into the fourth quarter, but I would expect something late September.

Okay. And then as to sort of -- I've realized you don't want to speak for them, but what would your -- how would it affect your plans if one of them wasn't to move forward?

Well, based on the current structure, in fact the Georgia Power Board voted, made a recommendation to the Southern Board. We concur with that. We are moving forward. Anything that was an alternative as a result of any of these governance processes, we just have to take that up at the time.

Okay. And then maybe if I could just -- one more on the -- looking at the sort of performance slide, where you show the metrics, what happened with the top one where it seems to kind of move sharply higher in July? And I know there's been some reports that you shut down work at the site for a day or 2. Could you talk about that?

That was it. Yes, that's pretty much it. Look, if you look at kind of the general trend, we've suggested, I think for a couple of earnings calls now, that while we've been going very well -- and in fact, if you go back in time and look at kind of the December 17 where we were really beating this green line, which is predicated on a 21-month schedule or a April 21, April 22 completion date, remember that variance was really because we worked through some periods, where we had planned otherwise to have a lot of dislocation in work from holidays. So that's why we've made up a lot there. And then we started saying, certainly, as we approach early part of this year, when we start working in some rather confined spaces with the reactor vessel core that we thought that we would see some erosion against that 21-month kind of schedule. The other thing that I think is important earlier this spring would be, we had a ton of rainfall and that impacted our ability to deploy productively. But I think the spike at the end, you got to be a little bit careful, this is a 4-week rolling average, but a lot of that spike maybe attributed to the 2 day-or-so stand-down on the site.

And what was the story there?

Sure. I think it was just recalibrating all expectations on-site, whether it is leadership's oversight of personnel, whether it is the commitment of personnel to complete their taxes efficiently as we need. It is medicine that we take from time to time that is painful, but generally produces good long-run results. The focus is to meet with year-end completion percentages. And we just took tough action to recalibrate personnel on the site to make sure that happens. And I think the results following that have been pretty good.

Yes. And then just finally, you've given this disclosure that electrician and pipefitter staffing is between 85% to 90% of plans. Could you just calibrate that to the prior disclosure, where I think you needed to hire 700 of one and 400 of the other by October. I think that was what was in the VCM, like how many does this 85% to 90% mean in the context of that target?

That's kind of where we are now versus the plan. We need to continue to ramp up I think our staffing projection would show we reach our peak in November. I think we feel really good about where we are in the pipefitters. I think the electrician is the one that continues to require focus. We have a lot of different arrows in the quiver to address that. We still believe we can hit everything we need, but it goes to getting workers from Canada, it goes to resegmenting work on-site, it goes to perhaps getting personnel from Puerto Rico and other areas. Look, I talk to Brendan Bechtel, either in person, on the phone, text, e-mail, people on the site are focused on this. We absolutely realize that we need to hit these targets. People remain confident, but I think it is the biggest risk area we face right now.

Do you have a number of how many more you need to hire?

Yes. There's a schedule. I think we can get it for you. I just don't have it right at my fingertips.

I think the best way to think about it is -- is current populations are at about 2/3 of what the expectation is by November.

By November. But we can get you more detail on that.

But does that -- you said by November that 85% to 90% of plan, is that -- so those are not conflicting comments?

Yes. Plan is like where we are now and then we need to add about 600 more by November.

And is that 600 relative to the 1,100 of the -- of both categories that was disclosed in the last VCM or relative to the 700?

Yes, it's just the electricians. And yes it is relevant to where we were before.

Our next question comes from the line of Steve Fleishman with Wolfe Research.

I think staff of the commission has been saying again that there's a not fully integrated project schedule. Could you talk to that, because it seems like that's pretty important to having confidence in these numbers.

I would argue that we have a good schedule. We continue to work on refining the schedule, but that's something that is ongoing all the time. In fact, I'm just looking at -- I was just reviewing this morning even, the construction milestones for the rest of the year. There's plenty of detail here and I can go into tens of thousands of lines of detail. But I have 20 big things that have to happen during '18, and I would argue something like on Unit 3, 18 of the 20 are -- have been met or are expected to be met within the parameters, only 2 are not. They're off by, on one case, 1 item a month, another case, a little over a month and neither one is critical path. They both have plenty of float left. On Unit 4, it's 16 out of 20. The variances look like a week, 2 weeks and 3 weeks, again, none of those are critical path. We completed the resource-loaded schedule in May, and so this is something that we always -- this is an ongoing process that we always look at refining the schedules and as we see new expected completion dates or as we see actual performance, it's different than planned. We always review the schedule. But I would argue, we do have an integrated schedule right now and we are meeting it.

Okay. And just I know the dates are November, 21, 22 are the same. Your other schedule had like an earlier time line. Can you -- could you just tell us what your internal schedule is relative to those November dates? Is it still 7 months ahead or...

Yes, yes, yes. It's what we've said before. We've been managing the site to what's called a 21, not 29 month. But what that means is, April 2021 for Unit 3 and April 2022 for Unit 4. That's what we're managing the site to. And the data we show and the metrics that we've had in these earnings calls, I guess really since we've taken over, would show that early on, we were even beating the 21-month schedule, the April schedule, that was at the end of '17 roughly. And we said that we thought that those achievements would be challenged, because we're moving into a very tight, constrained part of the site, the nuclear reactor vessel. It's just a much closer environment with a lot of people and a lot of material. And we thought that, that progress would be challenged and in fact that data has followed precisely what we've suggested.

And Steve, I'd say that the direct schedule performance index and the direct cost performance index that we show you is based on that April time schedule.

Okay. And then just lastly, just -- could you -- I'm sure you informed the commissioners and political leaders ahead of this, just any reaction from them to this news? Obviously, shareholders are absorbing most of it, but could you just...

I -- yes. Yes, we have, I would argue that the commission remains supportive of the project, as does the broad political public here in Georgia. If you think about it from a customer economic standpoint, customer impact standpoint, because we're making the tough decision not to include these base capital costs today, the same customer impacts remain today as existed in VCM '17 when this project was approved.

Our next question comes from the line of Stephen Byrd with Morgan Stanley.

Just wanted to talk about the contingency. You mentioned there could be some potential in the future for customers to absorb that. Can you remind me, where are we at the moment in terms of how the commission calculated the net present value to customers of this project? I'm just sort of thinking about the incremental changes to that net present value over time. I just wanted to level set where we are at the moment?

Yes. We can -- somebody should check me after the call. But as I remember, the calculations back in VCM '17, there was something like $2 billion of value to customers by pursuing this course of action. That's what I remember about the present value benefit. If that's not correct or if there are degrees of freedom around that, we'll get back to you. But that's what I remember. And recall with the action we have taken today, that's -- those economics are preserved.

Understood. And then I have more of a -- just a mechanical question around the joint owners. If the joint owners chose not to move forward and Southern Company chose to move forward, mechanically, how is that handled, I'm a little rusty on how that would sort of mechanically work its way through?

Yes. So the technical answer there is that the project would be deemed to be canceled, I believe. And then, of course, you could take a variety of different paths beyond that. But the technical answer is, if you don't get the 90% vote, the project is canceled. Then you have to figure out how or whether to proceed beyond that. There is no [prescription] per se beyond that action. Of course, we can all negotiate whatever. But that would also require Public Service Commission approval and a variety of other things.

Understood. So Tom, in that scenario would that likely involve commission involvement in terms of reviewing the plan at that point if the project is actually canceled.

Of course. Yes, it would, of course.

Our next question comes from the line of Julien Dumoulin-Smith with Bank of America Merrill Lynch.

So, just following up on Georgia Power's balance sheet just -- in terms of the authorized equity ratios and how you're thinking about the latest write-off? I know you talked about corporate level equity at this point. Can you just specify how you're thinking about financing at that level and just how you think about that perhaps having an impact on next year's rate case if at all?

You bet. You may recall that Georgia Power reached an agreement with the Public Service Commission following the new tax legislation. It was constructive and was designed to support their credit quality, which is so important, as we think about building an asset like Vogtle 3 and 4. The solution in order to reach a similar FFO-to-debt calculation was to increase the equity ratio from 50% to about 55%. They put that in place, effective immediately essentially, and also said that they would address it again later in the 2019 rate case. So we've been down-streaming equity into Georgia per that order, and the plans that we've laid in front of you today that relate to the $800 million additional equity requirement, also are consistent with that plan. And just to review the bidding, because I think it's informative, when we got the new tax law, we thought it was going to be about $7 billion of incremental equity across the system and that was associated with also increased equity ratios. With the transaction that we announced with NextEra, we essentially took $3 billion off the table, in other words, we were carrying about assets that were worth about $3.5 billion on our current valuation and sold them for about $6.5 billion. So the $3 billion netted against any future equity requirement. Further, we announced the forward sale to tax equity of the production tax credits associated with wind, that's another $1 billion. So the $7 billion was reduced by the $3 billion and then reduced by the $1 billion and so it is now net $3 billion. When we think about the actions that we are taking this morning and the additional $800 million, the $3 billion becomes $3.8 billion. And what we said earlier in our opening comments is that we still don't believe that requires any block sales, and we believe that we can handle this, therefore with at-the-market sales or our normal plans as well as investor-friendly equity. We think we've got plenty of gunpowder to handle this issue from an EPS standpoint. The effect this year -- and we've increased the equity in the EPS range from $2.80, $2.95 now to $2.95, $3.05. And we think the dilutive effect of this action today is only about $0.01 this year but within the $2.95 to $3.05, $0.02 in '19 and $0.05 kind of thereafter. And what we also said is we will undertake plans to reduce, eliminate that effect.

And Julien just to give you a little bit of this -- flavor of this mechanically, because the expenses are probable, we will take that write-down at Georgia Power, reduces equity, we will -- it -- however, it is paid down over time, this is part of our future expectation for constructed costs. But because we want to maintain the capitalization there for regulatory purposes, we will inject the $800 million today. This will improve FFO-to-debt in the near term, but certainly the expectation is that it will be used to fund construction over the longer term.

And just to underline what Drew is saying that, what we have done today has made a new estimate to complete. Those are dealing with not actual expenditures per se, but rather future expenditures. But we're taking the action immediately to improve the balance sheet. So from a cash standpoint, there's a difference, that actually works to our credit quality advantage.

Let me clarify this, just to be exceptionally clearcut about this, the $0.05 that you just talked about over time, none of that pertains to any change in the earnings ability for the asset itself, right? This doesn't change any of the -- basically track or earnings. This is simply a question of balance sheet and dilution impact.

That's exactly right. It only relates to the incremental equity that we are using in order to preserve credit quality.

And sort of to clarify, earlier, your response to Steve's question on the -- this tight construction period here. Can you elaborate a little bit more on when we're going to be, "through that," If you will, right, I suppose over the next little bit you seem to describe that it's a particularly difficult stretch of construction. When do you anticipate to be through it per your definition? And more importantly to that also the hiring ramp as well in tandem, right? I suppose both seem to go hand-in-hand with the schedule.

Yes. I think the next 18 months, Julien, are where we're seeing the big intensive pressure. After about 18 months, we see a pretty good ramp down in terms of staffing, et cetera, on the site. So something like that.

(Operator Instructions) Our next question comes from the line of Michael Weinstein with Crédit Suisse.

Just to follow up on the dilution and offsetting it with -- offsetting the $0.05 out in the future. Is that mostly going to come from cost cutting or is that part additional project growth and rate base growth such as I'm thinking like the grant mechanism in Georgia? What do you see is offsetting the diluted impact?

You know it's all that and potentially, investor-friendly equity as we've discussed before. We -- if we just pick Elizabethtown, for example, I think AGL made a heck of an acquisition there in the past, and you're carrying value there. I'm looking at Drew, it was around $700 million, you sold it for $1.7 billion. So you picked up about $1 billion solely on Elizabethtown. As I described the economics of the Florida transaction, we picked up $3 billion there. The other thing that I think is important to note, our cost position, and we should think about it company by company. For example, Georgia Power, remember basically postponed an action in 2016 with its normal 3-year accounting order process. That's pushed into '19. Georgia Power has already done a whole lot of cost management, been able to maintain an earnings profile that's been really good. And in fact, by our own data, Georgia Power would show their cost metrics are about top quartile in the industry. And the other thing that you should see as an evidence, when we talk about improving our earnings range, I hope -- I'm really encouraging us all not to treat this as a precedent, but because our numbers are so far ahead of our original guidance, we decided to give you new guidance at this call. Normally, our process has been that we give original guidance at the year-end call, which has been the end of January, early February, and we only update that in our October call after we get through the summer month. That has been our process really even going back to my days as CFO. We were just so far ahead, $0.30 ahead, that we felt we ought to go ahead and change the guidance from $2.80, $2.95 to $2.95, $3.05. Part of that performance has been our performance on cost recognition and the whole modernization effort. So I think it's -- Michael, I think it's all the above. I think it's cost management. I think it is the deployment of modernization to give us greater resilience, better customer service, increased CapEx and then, of course, investor-friendly equity.

Right. And a follow-up on Julien's question. What do you see is the next big cost pressure coming up over the next 18 months? Is it -- I guess, right now, we're in the middle of a -- kind of a labor squeeze. What are the -- what's the most expensive item over this next 18 months that you're going to be monitoring going forward? Is there a particular piece of equipment or a type of integration that's happening that would be particularly costly?

It isn't so much of that, because we have all the major equipment in place. It really deals with what we've been saying for some time now and that is our ability to deploy labor productively on-site. That's going to help us get to our schedule and that has certainly cost ramifications. We've got to keep productivity on the site up and actually improve the amount of hours worked every month on-site, as we get through this ramp-up process into November and then for the next 18 months.

All right. So there's no critical path item as there was when we were still installing modules?

No, no, no. There's always critical path. I mean, critical path, by definition, is whatever work is required that really sets the time frame in which you will be ready to go and service, for example, remember, I just mentioned the 20 major construction milestones this year for Unit 3 and Unit 4, and I gave a broad outline when I was talking to Fleishman, the critical path right now is in the auxiliary building. And that's kind of critical path, because successful completion on time of the auxiliary building allows us to begin testing of the major other components, which will set the time frame for the rest of the schedule. We have no major material components, everything is on-site. It's really a matter of putting it together at this point.

All right. I'm sorry if you said this before, I mean, when is the auxiliary building or part of it going to be completed and [through there]?

Let's see. Well, I'm looking through the end of this year. We have kind of by November 29, and we're ahead. The schedule right now would call for December of '18 or essentially the control room in the auxiliary building to be in place, and we're actually beating that right now. And that's based on the April schedule. We're beating it by not a whole lot, by about a week on each of the concrete floors, et cetera.

Our next question comes from the line of Michael Lapides with Goldman Sachs.

Tom, I'm sure you're privy -- or have seen data, especially given your role with the Federal Reserve down there, about labor conditions in the broader market. I'm just curious, how would you compare the labor differences that you're seeing at Vogtle 3 and 4 versus what kind of other large either manufacturing or industrial construction projects in the region are seeing?

Yes, right. I think what we're seeing is skilled labor is kind of the most intense part. It's a fascinating question. We are seeing kind of a spotty labor constraint around the United States. So IT, high-skilled manual labor, pipefitters, electricians, electricians specifically, because there's other activity going on around the United States, and it's requiring something special to draw those people to the site. That is one of the big change conditions that we have seen since the original ETC was put in place that we're reflecting today. The per diems that we have put in place appear to be working. We do appear to be attracting more people. And interestingly, our turnover, once we've gotten them on-site, has been cut in half, though we had been seeing turnover kind of over 10%, 12% somewhere in there. Turnover now is around 6%, so -- 6% to 7%, somewhere around there. But anyway, we're able to attract and retain better with these per diems.

Got it. That's super helpful. And Tom, one follow-up and I hate to ask this, but almost have to, given what's going on in the neighboring state -- 2 states over, what in the original nuclear law from 2007, 2008 is the process for potential cost recovery if the project is abandoned during construction?

Yes. We have a law in place that basically says any prudently incurred cost is recoverable. And recall, there are at least 3 segments of costs that have been ruled on over time, up to -- and I hope I get these numbers right, up to about $4.5 billion-or-so have already been deemed to be prudent, up to about $5.7 billion-or-so have been -- wait, up to about $4 billion have been found prudent, up to about $5.7 billion-or-so have been presumed to be prudent. And then up to the $7.3 billion, they are deemed to be reasonable, but the burden is still on us to prove prudence. I think those are the 3 separate buckets, and if I've missed any of those numbers on those buckets, somebody correct me, but I think broadly, that's where we are. And the prudence would determine that it is recoverable.

Got it. And is there a set regulatory process to go through that was laid out in the legislation or is it just kind of enabling legislation and the owners and the PSC would kind of have to figure out what the process or docket would look like?

The PSC will make the prudence determination and then it will apply against law.

Our next question comes from the line of Paul Ridzon with KeyBanc.

Have any events in the past triggered a co-owner vote [that needed] a 90% majority?

Yes. The -- I guess there's 2 triggers that we think about: one is a new ETC in excess of $1 billion, $1 billion or more; and the other one I think relates to a lack of recoverability. And in fact -- and Paul, one other issue, this 2 trigger feature was an agreement that was modified last year at the time we decided to go forward.

And I think you earlier said that you would not take $700 million of the $1.1 billion. What about the $400 million contingency?

Yes. So it's essentially this determination. We think of the $700 million, they were prudently incurred and reasonable, okay? But because of the proximity to VCM 17, we think for the good of everything going forward and in order to maintain momentum, we're not seeking recovery. With respect to the $400 million, contingency has never been part of -- in a broad sense, part of the allowed costs. What the commission likes to do in the practice of the staff and frankly, we follow that, because contingency by its nature is something that we think we'll spend, but we don't know what it is just yet, we don't include those. As we -- as these costs become known, then we would submit them for recovery. But the $400 million right now is an estimate, but we don't know where we will spend it. As we know more, we preserve the right to ask the commission for recovery. There is no cost cap, that's been proven before by law and VCM 12 and 17.

And then lastly, you kind of blew right through your guidance, what were the big drivers relative to your thinking on the last call?

Yes. It was really 2 things: one was kind of the success we had with the sale of assets to NextEra, and the lack of having to issue new equity this year; and the second was, the success of our modernization efforts, that is kind of the dual issue of cost management and increasing CapEx to improve resilience in customer service. Drew?

I'd say, one of the largest items is the success we've had with tax reform implications in each of the state regulatory jurisdictions. And so we've seen very positive and productive outcomes from Georgia, in particular, that relates to the -- both the power and the gas LDC and also in Alabama.

I know that it added $0.03 in the first quarter and $0.05 this quarter, what do you think the full-year impact is -- of that would be?

Pretty decent run rate as you've seen in the third quarter as a lot of the stuff matures. The biggest driver in the future will be the increase in equity content in the Alabama utility and Alabama Power, and so we'll just have to track that through the next couple of quarters.

Our next question comes from the line of Ali Agha with SunTrust.

First question, Tom, as you said, your equity needs previously had come down to $3 billion and now they are $3.8 billion with this extra $800 million. Can you just remind us how we should think about that? The $800 million, obviously, comes this year, but the base $3 billion, should we assume that's sort of evenly distributed over the 5 years? Or how should we be thinking about how that equity gets layered up over the years?

I think that's probably -- Ali, it think that's probably a fair way to think about it. We'll use our traditional programs of dividend reinvestment and then also sort of an at-the-market program that will begin shortly. But our intent is to move that equity out commensurate with some of the spend that we're doing. And even though our projection is changed, the 36-month time frame really is intact.

Yes, it's a reasonable modeling assumption, just to put that in ratably.

I see. Okay. And how much have you done, if any, through the first half of this year?

Less than a couple hundred million dollars.

Okay. And also that -- to clarify the comment that -- as you pointed out, you had this -- if you model it out, there's a $0.05 dilution that comes in from the extra equity. And you've talked about keeping the 4% to 6% growth rate intact. So is the implication that you're going to offset that $0.05, or is it that even with the $0.05 dilution, you're still within the 4% to 6% range? I want to be clear what you were conveying there?

Yes, yes. I know, it's a good point of clarification. If we did nothing to take away the impact of the $0.05 long-term, this is in the 2020, 2021 time frame, we are still within the 4% to 6%, okay? And we intend to diminish that impact over time through our actions, through modernizations, special investor-friendly equity or whatever. So even without any effort to eliminate -- reduce the $0.05, we're still within the 4% to 6%. My point is, we're going to attack that with great vigor.

Understood. Got it. And then with regards to the investor-friendly equity, Tom, if we look at your portfolio, are the opportunities more at the Southern Power level? I know you're monetizing the wind, you're getting $1 billion from that. Are they at the gas level? Is there more to be done on electric? Can you just give us a sense of where there is opportunity in that portfolio?

Yes, I think, we've kind of shown our hand, if you look at our portfolio, Ali, as you have, we have been, I think, very disciplined buyers and sellers. Recently, it has been Elizabethtown and then the set of assets to NextEra, where NextEra, I think, had special interest in pursuing some assets. We think we've got an argument anyway that a lot of our assets are undervalued in our current valuation. I think if you projected kind of Elizabethtown values on all of our gas assets, you would have a different valuation for Southern Company. What we're able to do, I think, is to be proactive and monetize some assets at higher valuations than otherwise you would expect to see as if we issued equity on our own. That has been the core. Everything we have done, from an investor-friendly standpoint, has been accretive. We think we still have the capability to do that when you look at the different pieces of our portfolio.

And Ali, I'd say, we were asked this question quite a bit, what's core and what's noncore, and reality is that it's -- the simple answer is that it is all core. There are certainly some things around the edges at the margin that we have to be responsive to. But our -- we think we've built the portfolio of assets that we really enjoy operating.

Got it. Last question, more mechanical, if you will. Your effective tax rate on an adjusted basis seems to be coming in lower than what we had. For modeling purposes, what is the right effective tax rate we should be using for the adjusted earnings trajectory?

Generally, right around 21%.

Our next question comes from the line of Angie Storozynski with [Macquarie] Group.

Okay. So 2 things. One is -- so it looks like the increase in the cost estimate, it has to do with labor-related issues and supervision, et cetera, but nothing to do with actually steel prices, et cetera. So I'm just wondering if that's a next issue that might arise? And secondly, on the financing of the incremental equity with potential asset divestitures, I mean, I understand that you can get very good prices for some of your assets. But by shrinking the company, in essence, you are increasing your exposure to this project, in a sense. And so, I mean I know that it actually might be still prepared to issuing straight-up equity, but just if you could share your thoughts on these 2 topics?

Yes, Angie, that's a great question. In fact, let me just hit that one first, and I'll come back to your first one, I think. When you think about -- another way to think about what we did with the Florida assets, we sold 5% of our earnings, that goes to your point of, well, you're increasing your exposure. But we sold 5% of our earnings for at that time about 12% of our market cap. It was enormously accretive. And when you think about exposure to earnings, when we do accretive things, that actually decreases the exposure from an accretion dilution standpoint. So I think when you look at the results, [cash], Elizabethtown, same thing, it was the highest valuation ever paid to our knowledge anyway, 37x earnings on a gas distribution asset. So I think the way you should view any sort of these investor-friendly divestitures, have been, it's not sales at the market, because sales at the market would do exactly what you're suggesting. These are sales well above our current valuation and therefore, they are accretive, and they are accretive to the point of overcoming any exposure -- any increased exposure to Vogtle 3 and 4. I think the math will bear that out pretty clearly. On the first part of your question, you referred to steel [plates]. Let me be very clear with everybody, and I think we've said this in several calls that the major equipments on-site, we don't have big exposure to that. We do have almost -- I guess, most of our steel is already purchased. We do have commodities, but we think we're accounting for that in this estimate. And the commodities go to the really small things. It goes to the small pipe. It goes to the wiring cable, it's -- I think the issue really does go more to deployment of productive labor on-site and maintaining hours worked per month so that we can hit the schedule and everything else that we adhere to. And so far, our estimate of schedule remains at -- we're confident on 29 months and we're performing ahead of that, right now. So I guess that's what I'd say. Even the subcontracts, which was a big part of what we started seeing here in late May, when we started letting out the subcontracts and they turned out to be significantly above cost from what we estimated in the original ETC, those tend to be labor-related as well.

Okay. And now -- so just one follow-up. So how do you come up with those contingencies? I mean, [especially for us to say] if $400 million is actually a large contingency or not. And it seems like your previous estimate has what's perceived to be very conservative and also included contingencies and now -- I mean, just -- how can we actually get appeased by this one?

It's -- again, it's a terrific question and one we ask ourselves all the time, how do you know you got enough? When we did the original estimate, you may remember from all the work we did that we had lots of different input into that estimate. And I think I kind of covered some of this in the script. But more specifically, we had the input of a variety of consultants. We had a completely separate path of a different consultant, give us their own estimate of what ETC would be. And then we took the ETC and went through the regulatory process, even the independent monitor, it was thoroughly debated, even the independent monitor thought it was reasonable and the process that we followed was sound. So we think we did a reasonable effort at the time that we made the ETC. At this new estimate, when we started seeing, as I mentioned before, trends that showed our contingency original was getting consumer faster than we thought, and especially in late May, when we started getting back feedback on the subcontracts that we got from Westinghouse, and I can tell you, when we first got the passover from Westinghouse's subcontracts, we said, "Gosh, let's add 50%." Well, now in hindsight, we think we should have added over 100% cost. And in some cases, it's not just the cost, but the scope has been bigger than what we expected. We had KPMG take another look at our new estimate, in terms of contingency. We've worked with Bechtel and others. We develop something we call a risk register. And what we do in a risk register, for items that we don't have complete transparency on, although we know where we believe they will be, we actually take a range of a low and the high and we perform analysis as to probabilities and we come up with a probability-weighted contingency estimate. This is essentially how we develop the estimate. We look at line items, we involve site management and we included in an overall assessment as to the project. Does this 35% contingency as per the $1.1 billion increase look reasonable? So we do all the kind of quantitative testing. We do the qualitative judgment kind of testing. To the best of our ability, we think we've got a sound estimate here.

Okay. And the last question. So okay -- so shareholders are eating the $700 million. Now you're about to file the VCM report. I thought that those reports are actually just to true-up the actual cost of the project and given that, as you said, there is no cap, I mean what's -- what kind of assurance do we have that next VCM is filed and there is another cost increase and another portion of that cost step-up has been absorbed by shareholders?

Yes. So we're taking a reserve today for the entire amount of the $1.1 billion on a pretax basis, okay? So that is a tacit acknowledgment that we're not seeking recovery of the $700 million base capital increase. It does not address the contingency that is the $400 million balance and that's because we don't know exactly how, when, what, we will incur those costs. We believe it is a reasonable estimate of what may occur. Therefore, we included it in the reserve. But because we don't have knowledge, we can't ask for recovery yet. So we've taken an income effect for the whole amount. As we go through each VCM and as we start to eat into that contingency, there will be some analysis of whether we get to recover those costs or not. But we've already taken the accounting hit for it, okay? And do let me -- one last thing, just to say it again, the $700 million that we've identified, that we are not seeking recovery, was really due to our judgment on maintaining project momentum and its proximity to the December 17 decision by the PSC.

Our next question comes from the line of Praful Mehta with Citigroup.

Thanks for the sitting through the marathon session. I know it's not easy. Just coming back to Vogtle and just stepping back a little bit, right? The expectation was that most of the risks were managed at this point and it's more of a regular construction project. And now we have such a big cost increase, it almost seems like the unknown is what we are kind of dealing with, right? The consultants haven't dealt with it before, obviously, your team hasn't done these kind of projects before. How do we get comfortable and how do you at your stage? I know you've clearly done the contingency and you've kind of fought through it. But at some point, there is a level of unknown in these projects that everybody is dealing with. And so how do you get comfortable with it and how do you manage that risk that every other earnings call, we don't have some concern on incremental cost that was just unknown that we just -- it's something new that's come up?

Yes, Praful, thanks for that. Very reasonable question. Look, I think we should take comfort in that. Well -- yes, we should take comfort in that. We've been on-site now in this role now for about a year. And for a lot of the estimates that we used in developing the ETC, they are no longer estimates, they are reasonably known. In other words, I want to say of the subcontracts, we have about 75% of them, are pretty well known, in other words, actual and all that. There's still 25% or so, 30%, somewhere in that range, where we've gone out on the subcontract. And at least we know bandwidths of where we think they'll come back. Now we still have time and material situations and we've got to be productive in terms of how we follow that work, because a lot of the subcontract work depends on the work that Bechtel does and so maintaining schedule is so important. I think one other thing you can take some comfort in is that the schedule part of this has still been working pretty well, although as we continue to say, we're in the challenged part of that schedule. So our actual performance is better than kind of the November time frame. But still that's the part that we're really focused on. The other thing that I think you should take some comfort in is that we do have essentially a complete design. We do have a technology that is being demonstrated right now with 4 units at least being in startup in China. I think there are a lot of factors that cause us to have a lot more confidence today in the fact that we've taken additional contingency, 35% of this new estimate. Now having said all that, I've got to acknowledge, and we've seen it before, we don't know all future conditions and we don't know how all this will turn out. What we're giving you is our -- is, I think, the most reasonable judgment we can make with additional contingency.

Got you. Fair enough. Understood. And secondly, in terms of asset sales or potential asset sales as you look to fund some of the equity need, one of the points you made earlier on one of the questions was that it's always -- it's accretive because relative to where Southern is trading, the value you're getting from those assets is clearly at a higher multiple. But I'm sure you'll -- when you look at it internally, you don't value your entire portfolio within Southern at the same multiple. As in, different pieces within your business are trading at different multiples. So it's really probably unfair to compare it to a Southern consolidated multiple. So I just wanted to check, when you compare and when you try to look at, okay, what is an accretive price, and as you look to divest assets, how are you kind of benchmarking the right multiple?

Yes, Praful, it's absolutely right. I'm just trying to use something that everybody else can see, Okay? I'm just trying to use a reasonable benchmark that people can look at. When you look at 37x earnings in an LDC, I think everybody would say, well gosh, relative to kind of how it would be -- how we essentially, if you look at the buy and sell, what we bought it for and what we're selling it for, it's pretty clear that we bought very well with both AGL and SONAT, and that we've sold very well in respect of the pieces of those assets. And in respect to that, they are enormously accretive. I would just give you anecdotal information, even Florida City kind of went off at about the second-highest multiple ever paid for an LDC with the first being Elizabethtown. It was pretty close to the Piedmont price. The Gulf price, to our knowledge anyway, was the highest multiple paid for an electric asset and we think there were certain conditions, and NextEra, which made them willing to pay those prices. You're absolutely right. We certainly have a risk return profile for every asset that we own and those are unique as per every asset. That would include every asset owned by Southern Power, for example. So your point is exactly right. My shorthand and talking through just is something that everybody can point to on the street without knowing the vagaries of how we value every asset internally.

And I think that's pretty consistent with what you always talk about, Tom, in terms of risk and return. And Praful, we focus really on evaluating the growth of an asset, its opportunities for investment, its scale and its scope, and so it really is a multi-variable equation. We do have to compare it for the costs to our shareholders of issuing additional equity. I think we feel comfortable certainly in the $3.8 billion that Tom talked about today that, that really is equity that can be issued in normal course without a lot of pressure. But we will still evaluate all options versus 5 or 6 major investment criteria within the core. But we've had to take advantage of dislocations where the market is valuing certain segments of the portfolio maybe more aggressively than others.

Our next question comes from the line of Ashar Khan with Verition.

I was just trying to get a better sense of the earning powers going forward if I can. So if I understand correctly, the earnings that you have improved for this year, as you said, there are [force] factors, which is lower dilution from equity and better earnings from your subsidiaries, because of the plans. So can one say that this is probably the right base from which one has to build going forward? Except I don't know if you can help us, that from the asset sales that you have announced to date, and which I think so will not be part of the earnings profile going forward, how much earnings do we lose from the assets that you have announced for sale or have completed sales, which is in 2018 forecast? And if you were to take them out and do a pro forma for those asset sales that have been announced or will be completed as part of the NextEra transactions, how much earnings do we lose from the '18 guidance? Can you help us on that on a dollar basis?

Yes, sure. But let's -- yes -- and -- Drew and I are -- I'm looking at Drew. So let me take the first shot and let you correct it or whatever. Go back to the math I gave you on the Florida transactions. We sold 5% of earnings and we got [for] 12% of market cap at the time. The offset of the equity and therefore the $3 billion incremental value we generated by that transaction was way more accretive, $0.10 in this case -- $0.10-plus actually, than the lost earnings, okay? So if you just remove Gulf Power, you lose earnings of X, but we're able to increase earnings by over $0.10, because of the value we created by the transaction, okay? So that takes into account all of the removal of equity and debt and everything underlying, the earnings of an asset, and because the price was so high, it was accretive, even removing those earnings. And what we are able to...

It was accretive by $0.10 or what is the accretion, exact...

Yes. What we said on the Florida transaction, the one with NextEra was -- it was actually $0.10 and actually a little better than that and what we did with $0.10, we took about half of that and we applied that against further reductions in debt to give us even more margin on the FFO-to-debt calculation. We really wanted to build a little shock absorber into our credit quality. The second part, therefore, the remaining $0.05-or-so, improved our ability to earn within the 4% to 6% range. Recall, we had established the 4% to 6% range, then we did the Florida asset. Then we said we're still within the 4% to 6%. So conceptually, we moved higher within the range. And then what we said as a result of this transaction, there's kind of $0.05 -- if we don't do anything, there's $0.05 negative carry beginning around 2020, 2021, somewhere in there. And we said we're still within the range even if do nothing. And then what I said was, we will work very hard to lessen or eliminate that effect. And then -- and what we said was a continuation of our modernization plans, which were partially the engine for improving our earnings this year as well as industrial-friendly equity and other strategies. Drew, improve that answer.

Maybe I'll try to answer a couple of the specifics that you asked related to what we've based off of and what the implications are. And if you think back the sort of the seminal event for us was the -- was tax reform, which led to a pretty substantial equity requirement, so that we could maintain credit quality of each of the underlying utility subsidiaries. And so generally, when we talk about growth that is off of the 2017 baseline that that established. And as Tom said, we've been working toward a 4% to 6% range. We felt like the opportunistic sale of the Florida properties reduced the equity burden and pushed us further up into the 4% to 6% range. Certainly, this write-down of about $800 million and its required equity raise, moves us down a little bit more in -- within that range, but still within the range. And our goal is to offset a lot of that activity -- or a little bit -- a bit of that dilution with internal activities related to modernization, cost control and a variety of other factors. So I think generally, our -- when you think about the loss in that income for those things, they are as we've described 4% to 5%. But the impact on EPS and our expected growth rate is basically unchanged.

Ashar, and I know you know this, but let me just remind us all for the record here. While we are in this construction period in Vogtle, as part of the settlement to go forward, Georgia had some reduced earnings rates. Once all the assets clears to in-service for Units 3 and 4, we go back to the normal earnings rates and so there's a little bit of a shape also through our year-by-year earnings, but I know you're aware of that.

No -- I'm aware. I was just trying, Tom, to build up my 2019 earnings profile for you. And so if I'm doing it correctly, I guess I wanted to do it before you announce it and I'm not surprised in the February call, is that it seems like that things that you have taken or the actions you have taken, the accretion is more front-end loaded. And with this transaction that is announced, as you said, the dilution, which you will offset, even if the dilution comes its way back-end loaded in the third year or so. So in essence, as we have started the year and where we are right now in the 1st week of August, there is more accretion -- upfront accretion from the asset sales, which should help the earnings profile in the near term. And I just wanted to make sure my conclusion on that or my -- the way I'm going is correct or wrong?

Yes, Ashar, of course, as with past practice, we'd be glad to follow up with you after the call to kind of refine that.

And our final question comes from the line of Paul Patterson with Glenrock Associates.

So just really quickly back on Vogtle. When we're looking at the cost increase, is there a breakdown, I guess, on sort of productivity and efficiency versus just sort of pure -- the cost of the labor itself and in terms of the price increase that you didn't sort of -- hadn't anticipated?

I'm sorry, ask that one again.

Well, is there sort of a -- do you have a breakdown in terms of sort of the efficiency or the productivity? In other words, there's a lot more people that you have to employ to sort of get a job done versus just sort of the increase, it sounded like that you guys were expressing in terms of labor costs than what you had previously expected. Do I understand that correctly that that's sort of the 2 components?

Yes that's right. Paul, one of the things that we're involved with right now that we are keeping our eyes on like hawks is the amount of productive hours worked in a month. So I would say, we're kind of in the 85,000 hours a month right now. We need to get that up to November by, I don't know, 125,000. That's kind of the ramp up that we are currently in. And so there's really 2 factors there, right? One is getting workers on the site. So that's the earlier dialogue that we shared about pipefitters and electricians and all that. And the second thing is once we get people on-site getting them to do productive work, so making sure that if they're X hours in a day that we actually turn ranches and produce results in accordance with what we think. That's kind of the trend that we are following right now and that will drive certainly schedule, which we're ahead of right now and costs.

Okay. So you're ahead of schedule, that's my -- so follow-up is that, because you're ahead of schedule, is that why these additional hurdles that you're seeing in terms of productivity, or what have you, aren't delaying your in-service date, is that how we -- I mean -- not extending the in-service date, do you follow what I'm saying? I mean, why is that, that you guys are having these cost issues, but it doesn't seem to be impacting the schedule?

Well, if you think about it, Bechtel, the cost performance index really relates to work being performed by Bechtel. And we are above the 1 there. But Bechtel has a contract, which has its own contingency and has its own -- I think if you -- I think the benchmark that we talk about internally is Bechtel on a 29-month schedule is about 1.4-or-so. Somewhere around there. We'd like to get them certainly below, we have been talking about 1.22, we'd like to get below 1.2 in order to keep our performance ahead of schedule as we've been saying.

Okay.

And I think it's also fair to say that a lot of -- about half of the cost increase that we're taking is in an effort to stay on track and lower the schedule risk that's there. And so that does include wage inflations per diems, specialized trade, a lot of the activity that -- and what we're [pro forming] is the completion of these projects in November of 2021. And that's certainly going to be a big component of why we've decided to spend these additional funds.

Yes. And, Paul, just another way to attack this thing. If you go back to this graph on, I guess it's Page 11 or whatever. But if that number, this cost performance index is at 1.24, that would indicate about a -- let me just do this, June schedule, somewhere around there.

Okay. And then just in terms of regulatory, have you guys foreclosed? I mean, to just make sure that I understand this, have you guys foreclosed any recovery associated with this additional cost? Or is it that you're just simply not going to be seeking it now?

We are -- yes sir. We are clear that we are not going to seek recovery on the $700 million. We are reserving the right, because there is no cost cap, on the $400 million in contingency. The reason that we have not included that in any estimate is really part of our past practice, the commission or the staff likes to approve contingency. As contingency becomes a real expenditure, we will then decide whether it is reasonable and subject to recovery. Operator, any more questions?

No. At this time, there are no further questions, sir. Are there any closing remarks?

Yes. Thanks, everybody, for joining us today. Certainly, this is not news that we welcome. I think it is -- it represents a reasonable estimate, as to how to proceed. I think it preserves our regulatory relationships. I think it preserves, I think, an equitable assessment of our stakeholders. I know that's painful as a shareholder, but I think in the short-run, this is pain that is worthwhile in order to reserve long-run performance. And I think we've demonstrated the long-run impacts here with the discussion around really even current EPS performance and how we've blown through the top of our set range with all the good work we've done this year, with the Florida transaction and with our own modernization efforts. But also would nod to the future effects of this announcement today. And I think it's our opinion that this action today preserves the best long-term value for our shareholders. Short-term pain, but long-term gain. We think we're able to maintain this performance and provide, I think, a very attractive risk return profile to investors. Thanks, everybody, for joining us today. We look forward to chatting with you soon. Operator, that's all.

Thank you, sir. Ladies and gentlemen, this concludes the Southern Company's Second Quarter 2018 Earnings Call. You may now disconnect.