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Southern Co
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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. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. 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's Second Quarter 2018 Earnings Call. Joining me this afternoon are Tom Fanning, Chairman, President and Chief Executive Officer of Southern Company; and Drew Evans, Chief Financial Officer.
Let me remind you that we will 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 this 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 as a $1.1 billion pre-tax charge which represents an increase in Georgia Power share of the projected cost to complete Vogtle 3 and 4.
We continue to project construction completion date of November 2021 and November 2022 for Units 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 was the first time that Southern Nuclear had brought access to Westinghouse's more detailed cost information, invoices, subcontract 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 Semi-Annual Vogtle Construction Monitoring Reports for 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 in 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 acknowledgement that work was still ongoing on key terms that could impact costs that the craft labor force may be unable to maintain their productivity improvement 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's share of completing the project. This cost reflected Southern Nuclear's as initial ETC net of the $1.7 billion Toshiba parent guarantee and partial customer refunds of that guarantee.
In the year 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 recognized 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 years' 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 was insufficient to fully offset forecasted cost increases. The new estimate reflects the Georgia Power's projected share of total costs has increased from $7.3 billion to $8.4 billion, an increase of $1.1 billion dollars. 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 it's in the best long-term interests of investors, customers and other stakeholders that we not disrupt project momentum by seeking approval of the base 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 and new contingency will be sufficient to take Vogtle 3 and 4 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 schedules to get to completion.
Meanwhile progress on construction continues. Several major milestones have been met and we've achieved scheduled completion date and we continue to project in-service date by November 2021 and November 2022 for Unit 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 for four AP1000 units in China which have loaded fuel and are currently in state-up phase.
I will now ask Drew to provide a few details on the financial aspects of the new project estimate.
Thanks, Tom. The $1.1 billion pre-tax charge reported for Georgia Power, which translates to a $790 million after-tax 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 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 are 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 a settlement for Mississippi Power Company 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 six months ended June 30, 2018, we reported earnings of $784 million or $0.77 per share compared with the 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 six 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 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 I turn 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 topic we've addressed on today's call. So let's go ahead and open the floor for questions. Operator let's take the first question.
Thank you Our first question comes from the line of Jonathan Arnold with Deutsche Bank. Your line is open. Please proceed with your question.
Hey, Jonathan.
Good morning, guys. Thanks for taking up our question. 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%. Can you just talk to us Tom about how confident you are around that process and what would happen in the event that one of them didn't come along?
Yeah. 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 process to 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.
What's the timing on when you think that will play out?
Yeah. Certainly it'll 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 – you know, I realize 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? I know there's been some reports that you shutdown work at the site for a day or two. Could you talk about that?
That was it. Yeah. 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 2017 when we were really beating this green line which is predicated on a 21 month schedule or a April 2021, April 2022 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 careful, this is a four week rolling average, but a lot of that spike may be attributed to the two-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 task as 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.
Okay. And then just finally, you've given this disclosure that electrician and pipefitter staffing is between 85% and 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 what does the 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 on the pipefitters. I think the electricians 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 re-segmenting 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?
Yeah, there is 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 current populations are at about two-thirds of what the expectation is...
By November.
By November.
We can get you more detail on that. It represents about 600 jobs...
But that two-thirds of November, but 85% to 90% of plan, is that...
That's...
Those are not conflicting comments?
Yes. Plan is like where we are now and then we need to add about 600 more by November.
Right.
And is that 600 relative to the 1100 of both categories that was disclosed in the last VCM or relative to the 700?
Yeah. It's just the electricians. And yes it is relevant to where we were before.
Okay, great. Sorry to, for all the questions though – thank you.
No, no, great. Thank you, Jonathan.
Our next question comes from the line of Steve Fleishman with Wolfe Research. Your line is open. Please proceed.
Hi, Steve.
Hey, good morning. I think staff or the commission has been saying again that there's not a full integrated project schedule. Could you talk to that, because it seems like that's pretty important 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 2018. And I would argue something like on Unit 3, 18 of the 20 have been met or are expected to be met within the parameters, only two are not. They're off by, on one case, one 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, 16 out of 20, the variances look like a week, two weeks and three 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 schedule and as we see, new expected completion dates or as we see actual performance that'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 2021, 2022 are the same, your schedule had like an earlier timeline. Could you just tell us what your internal schedule is relative to those November dates, is it still seven months ahead or...?
Yeah, yeah, yeah, it's what we've said before. We've been managing the site to what's called a 21 month, not 29 month. But what that means is April of 2021 for Unit 3 and April of 2022 for Unit 4. That's what we're managing the site to. And the data we show in 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 2017 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 is 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 the 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...
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 cost today, the same customer impacts remain today as existed in VCM 17 when this project was approved.
Okay. I'll let others ask questions. Thanks.
Yeah.
Our next question comes from the line of Stephen Byrd with Morgan Stanley. Your line is open. Please proceed.
Hey, Stephen.
Hi, good morning. Thank you for taking my questions. 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 want to level set where we are at the moment.
Yeah. Somebody should check me after the call, but as I remember the calculations back in the 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...
Okay.
...that with the action we've 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 like a little rusty own how that would sort of mechanically work its way through?
Yeah. So the technical answer there is that the project would be deemed to be cancelled 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 cancelled. 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 could 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 technically cancelled?
Of course. Yes it would, of course.
Okay. That's all. That's all I have.
Thank you.
Thank you.
Our next question comes from the line of Julien Dumoulin-Smith with Bank of America Merrill Lynch. Your line is open. Please proceed.
Hello, Julien.
Hey, good morning. Thanks for the time. 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 a 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 in 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 $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. We think the dilutive effect of this action today is only about a $0.01 this year, but within the $2.95 to $3.05, $0.02 in 2019 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 – a flavor of this mechanically because look the expenses are probable, we will take that write-down at Georgia Power reduces equity, we will – however it is paid out 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 is 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.
Yeah.
So from a cash standpoint, there's a difference, it actually works to our credit quality advantage.
Let me clarify this just to be exceptionally clear cut about this. The $0.05 that you just talk 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 tracker earnings, this is simply a question of balance sheet and dilution effect.
That's exactly right. It only relates to the incremental equity that we're using in order to preserve credit quality.
And sort of to clarify earlier your response to Steve's question on the 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 seemed to go hand-in-hand with the schedule.
Yeah. 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.
Okay. I'll let it there. Thank you very much.
Yes, sir.
Our next question comes from the line of Michael Weinstein with Credit Suisse. Your line is open. Please proceed.
Hi, guys.
Hey, Michael.
Hey. 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 based growth such as thinking like the grand (39:40) mechanism in Georgia, what do you see is offsetting the dilutive impact?
You know it's all that and potentially investor-friendly equity, as we've discussed before. Just pick Elizabethtown for example, I think AGL made a heck of an acquisition there in the past and your 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 we should think about it company-by-company for example Georgia Power, remember basically postponed an action in 2016, with its normal three year accounting order process that's pushed into 2019. Georgia Power's already done a whole lot of cost management, have been able to maintain an earnings profile that's been really good. And in fact by our own data Georgia Power, which showed 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 yearend calls, which has been the end of January, early February. And we only update that in our October call, after we get through the summer months. 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 that, Michael I think it's all the above. I think its 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.
Great. And a follow-up on Julien's question, what do you see as the next big cost pressure coming up over the next 18 months? I guess right now we're in the middle of a kind of a labor squeeze. 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 type of integration that's happening that'd be particularly costly?
You know 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 onsite. 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 onsite as we get through this ramp-up process into November and then for the next 18 months.
Right. So there's no critical path item as there was when we were still installing modules?
No, no, no, there is always critical path. I mean critical path by definition is whatever work is required that really sets the timeframe in which you will be ready to go in service. For example, remember I just mentioned 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 within the Auxiliary Building and that 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 timeframe for the rest of the schedule. We have no major material component. Everything is onsite. It's really a matter of putting it together at this point.
Right. Sorry, if you said this before. I mean, when is your Auxiliary Building part of it going to be completed and through that?
Let's see, well, I'm looking through the end of this year. We have kind of by November 2029 and we're ahead – the schedule right now we call for December of 2018 for essentially the control room in the Auxiliary Building to be in play and we're actually beating that right now. And that's based on the April schedule. We are beating it by not a whole lot, by about a week on each of the concrete floors et cetera.
Okay. Great. All right, thank you very much.
You bet.
Our next question comes from the line of Michael Lapides with Goldman Sachs. Your line is open. Please proceed.
Hey, Michael.
Hey, Tom. Thank you for taking my question. I'm sure you're privy or have seen data especially given your role with the Federal Reserve down there about labor conditions and the broader market. 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?
Yeah 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 constraints around the United States. So IT, high skill 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 sites, 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 onsite has been cut in half. So we have been seeing turnover kind of over 10%, 12% somewhere in there. Turnover now around 6%, so – 6% or 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 hate to ask this, but almost have to, given what's going on in the neighboring state...
Ask away.
...two 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?
Yeah. We have law in place that basically says any prudently incurred cost is recoverable. And recall there are at least three segments of costs that have been ruled on over time up to – 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 three 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 prudent 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.
Got it. Thank you, Tom. Much appreciate it.
Yes sir. Thank you.
Our next question comes from the line of Paul Ridzon with KeyBanc. Please proceed. Your line is open.
Hello, Paul.
Good morning, Tom. Have any events in the past triggered a co-owner vote that you needed the 90% majority?
Yeah. I guess there's two 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...
Tom, early...
And Paul one other issue, this two-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 seek $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 followed 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 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 in 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?
Yeah, it was really two 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 and customer service. Drew?
Yeah. 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 both the power and the gas LDC and also in Alabama.
I know that added $0.03 in the first quarter and $0.05 this quarter. What do you think the full year impact 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 – in Alabama Power and so we'll just have to track that through the next couple of quarters.
Okay. Thank you very much.
You bet. Thank you.
Our next question comes from the line of Ali Agha with SunTrust. Your line is open. Please proceed.
Hello, Ali.
Thank you. Good morning. 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? You know the $800 million obviously comes this year, but the base $3 billion, should we assume that sort of evenly distributed over the five years or how should we be thinking about how that equity gets layered over the years?
Ali, I 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 has changed, the 36-month timeframe really is intact.
Yeah, 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 of hundred million.
Okay. And also then to clarify the comment that as you pointed out, you had this – if you model it out, there is the $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.
Yeah, yeah. No, 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 timeframe we are still within the 4% to 6%. Okay. And we intend to diminish that impact over time through our actions, through modernization, special investor-friendly equity or whatever. So, even without any effort to eliminate, reduced 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 you 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?
Yeah. 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, we're asked this question quite a bit. What's core and what's non-core? 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 we think we've built a portfolio of assets that we really enjoy operating.
Got it. Last question is 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%.
21%. Got it. Thank you.
Thank you.
Thank you. Our next question comes from the line of Angie Storozynski with Macquarie Group. Please proceed with your question. Your line is open.
Hello, Angie,
Thank you. How are you? Okay. So, two things. One is, so it looks like the increase in the cost estimate has to do with labor-related issues and supervisions 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 two topics.
Yeah. Angie, that's a great question. In fact let me just hit that one first and I will 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 are increasing your exposure, but we sold 5% of our earnings 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, it 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, 37 times 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 play. Let me be very clear with everybody. And I think we've said this in several calls that the major equipment is onsite, 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 wire and cable. I think the issue really does go more to deployment of productive labor onsite 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 are 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...
Did I – yeah.
Thank you. So just one follow-up. So how do you come up with those contingencies?
Sure.
I mean, it's tough for us to say if $400 million is actually a large contingency or not. And it seems like your previous estimate was perceived to be very conservative and also included contingencies and now, I mean, yeah, I mean just how can we actually get appeased by this one?
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 was thoroughly debated; even the independent monitor thought it was reasonable in the process that we followed with 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 consumed faster than we thought, and especially in late May when we started getting feedback on the subcontract that we got from Westinghouse, I can tell you when we first got the Passover from Westinghouse of subcontract, we said, gosh let's add 50%. Well now in hindsight, we think we should have added over a 100% cost. And in some cases 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 developed something we call a risk register. And what we do in the 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 a high and we perform analysis as to probabilities and we come up with a probability weighted contingency estimate. This is essentially how we developed the estimate. We look at line items, we involve site management and we include it 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, 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's no cap, I mean what kind of assurance 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 pre-tax basis. Okay. So that is a tacit acknowledgement 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 include it in the reserve. But because we don't have knowledge, we can't ask for recovery yet. So we've taken an income affect 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.
Yes. Okay. Thank you.
And let me add 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 2017 decision by the PSC.
Okay. Thanks.
Thank you, Angie.
Our next question comes from the line Praful Mehta with Citigroup. Your line is open. Please proceed.
Thanks for joining us.
Thank you. Hi, guys and thanks for 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're 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's 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?
Yeah. Praful, thanks for that. Very reasonable question. Look I think we should take comfort in that. Well, yeah, we should take comfort in that we've been onsite 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 is 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 timeframe. 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 start-up in China. I think there are a lot of factors that cause us to have a lot more confidence today and the fact that we've taken additional contingency 35% of this new estimate. Now having said all that, I got to acknowledge and we've seen it before, we don't know our 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 accretive because it's relative to where Southern is trading, the value you're getting for those assets is clearly at a higher multiple. But I'm sure 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.
Absolutely.
So it's really probably unfair to compare it to 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?
Yeah. 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 37 times 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 is pretty clear that we bought very well with both AGL and SONAD and in 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. It's opportunity for investment, its scale and its scope. And so it really is a multi-variable equation. We do have to compare it to 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 five or six major investment criteria within the core, but we have to take advantage of dislocations where the market is valuing certain segments of the portfolio maybe more aggressively than others.
Got you. Understood. Thanks guys and surely you have done a great job with the asset sales there, so appreciate that. Thank you.
You bet. Thank you. Appreciate your questions.
Our next question comes from the line of Ashar Khan with Verition. Please proceed. Your line is open.
Hello, Ashar.
Hi, good morning. How are you doing? 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 are four 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 2018 guidance? Can you help us on that on a dollar basis?
Yes, sure. Yeah, Drew and – 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 our 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're able to...
It was accretive by $0.10 or what is the accretion exact?
Yeah. 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 the $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 assets, 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 we do nothing. And then, what I said was, we will work very hard to lessen or eliminate that effect. 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 investor-friendly equity and other strategies. Drew, improve that answer.
Well, 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 sort of the seminal event for us 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 it 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 within that range, but still within the range. And our goal is to offset a lot of that activity or a little bit of that dilution with internal activities related to modernization, cost control and a variety of other factors. So I think, generally when you think about the loss in net 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.
Hey, 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 has 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 is a little bit of a shake also to 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 the things that you have taken, or the actions you have taken, the accretion is more frontend loaded. And with this transaction that is announced as you said the dilution which you will offset, even if the dilution comes, its way backend loaded in the third year or so. So in essence, as we have started the year and where we are right now in the first week of August, there is more 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 the way I'm going is correct or wrong?
And Ashar, of course as with past practice we'd be glad to follow-up with you after the call to kind of refine that.
Okay. Thank you so much. So kind of you.
Thank you sir.
And our final question comes from the line of Paul Patterson with Glenrock Associates. Your line is open please proceed.
Hey, Paul.
Good morning. Can you hear me? Hey. How you doing?
Yes sir.
So just really quickly back on Vogtle. When we are 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 in terms of the price increase that you 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 the 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 experiencing in terms of labor costs than what you had previously expected. Do I understand that correctly that that's sort of the two components?
Yeah, that's right. You know 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 a 125,000. That's kind of the ramp-up that we are currently in. And so there's really two 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 onsite getting them to do productive work. So making sure that if there're X-hours in a day that we actually turn wrenches 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 cost.
Okay. So you're ahead of schedule, that's sort of my follow-up is that, so because you are ahead of schedule, is that why these additional hurdles that you're seeing in terms of productivity what have you, aren't delaying your in-service date, is that how we should – I mean not extending the in-service date, do you follow what I am saying, I mean, why is it 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 think – 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've 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.
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 and what we're performing 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.
Yeah, and Paul just another way to attack this thing. If you go back to this graph 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, just to 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....
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 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.
Okay. Okay. Thanks a lot.
Yes, sir. Thank you. Operator, any more questions?
No. At this time, there are no further questions. Sir, are there any closing remarks?
Yeah. Thanks everybody for joining us today. Certainly, this is not news that we welcome. I think 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 preserve 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 a 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.