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Southern Co
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Good morning. My name is Ciglan, and I will be your conference operator today. At this time, I would like to welcome everyone to The Southern Company Second Quarter 2019 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.
I will now like to turn the call over to Mr. Scott Gammill, Investor Relations Director. Please go ahead, sir.
Thanks, Ciglan. Good morning, and welcome to Southern Company's second quarter 2019 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, 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, Form 10-Qs and subsequent filings.
In addition, we will present non-GAAP financial information on this call. Reconciliations to the applicable GAAP measure are included in the financial information we released this morning as well as the slides for this conference call, which are both available on our Investor Relations website at investor.southerncompany.com.
At this time, I'll turn the call over to Tom Fanning.
Thanks, Scott. Good morning. And thank you all for joining us. This morning, we reported strong earnings per share substantially above our estimate and remain on track to meet our full year earnings target for 2019.
Our electric system has demonstrated resilience in what has so far been a hot summer in the southeast. We also continue to make meaningful progress at Plant Vogtle Unit 3 and 4 as demonstrated by the achievement of several milestones during the quarter. In addition, we are progressing well through an active regulatory calendar this year. We’ll cover all of this today.
So let me start with an update on Vogtle. The site continues to make progress and we remain focused on meeting the November 21 and November 2022 regulatory approved in-service date for Vogtle Units 3 and 4. Our strategy of working to an aggressive plan on the site remains in place and currently provides a six month margin to the November date.
There is no change in our total estimated costs for the project at this time. And we have not allocated any contingency, though the presence of a contingency reflects our expectation that we will likely utilize this reserve in the months ahead.
As we stated during the first quarter call, our focus is on achievement of major milestones, supported by adequate staffing and productivity. In May, we achieved initial energization for Unit 3, a major milestone for the project. In addition, we set the middle containment ring for Unit 4 and installed the generator rotor for Unit 3.
In August, we expect to begin our next major milestone for Unit 3, integrated flush activities on schedule with the site's aggressive work plan. Overall and including engineering procurement and initial test plan activities, the entire project is approximately 79% complete. For Unit 3 direct construction is 71% complete with a target to approach 90% by year end.
The site is averaged approximately 145,000 earned hours over the past three weeks with a year-to-date average of 133,000 earned hours through July. Now recall, the aggressive site work plan requires an average of 160,000 weekly earned hours for a sustained period of time starting later this year into next year.
To meet the regulatory approved November schedule, we estimate that we would need to average approximately 100,000 earned hours per week through the start of Unit 3 hot functional testing, which is essentially the completion of the construction phase for the unit.
We've been successful in hiring additional craft resources and supervision and now we have over 8,000 people working on the site across day and night shifts. As a result of these hiring efforts constructions weekly production capacity has risen and we are working to gain productivity improvement.
As we [Technical Difficulty], for example most recently our electrical scope for Unit 3, we see essentially an S-curve or a sawtooth effect. As we add a significant number of new skilled craft and field supervision, we initially see modest levels of improvement in earned hours then as the workforce matures productivity should improve.
You can see this effect in our most recent data. CPI is a trailing four-week statistic. However over the last month or so earned hours for our Unit 3 electrical have more than doubled. Looking forward in order to meet the aggressive site work plan we will need to sustain and improve this performance.
As a final note, it would not be surprising to see more fluctuations in CPI in the months ahead as we continue to add new craft and increase system turnover activities. We believe we are on track to meet the upcoming milestones in support of the aggressive site floor plan.
Now looking forward to the end of the year, we expect to be near completion of the integrated flush for Unit 3 and have the main control room ready for testing. Around the same time, the site should begin open vessel testing, which we have added to Slide 7 as another major milestone to track.
Open vessel testing verifies that water flows between the primary systems and the reactor and that the pumps, motors, valve and pipes function as designed. This is a key set of activities leading up to cold hydro testing which we anticipate will begin next spring.
The final major construction milestone is the start of hot functional testing. From there we will focus primarily on certifying systems, leading up to fuel load which would occur by the end of next year under the aggressive site work plan. And as we said previously, the aggressive site work plan is challenging and we work to meet it every day.
Ultimately success is bringing Vogtle Units 3 and 4 online on or before the regulatory approved November 2021 and 2022 in-service dates. Based on what we know today, we continue to expect that we have sufficient schedule and cost contingency to meet this objective.
I'll now turn the call over to Drew to cover our quarterly performance in greater detail.
Thanks, Tom. And good morning, everyone. Happy Shark Week. In the second quarter of 2019 we achieved earnings per share of $0.80 on an adjusted basis, $0.09 higher than the estimate we provided on our last call and in line with $0.80 of earnings per share on an adjusted basis reported in the second quarter of 2018.
The primary drivers of our quarterly results compared to last year are higher revenues associated with changes in rates and pricing, net of usage changes and warmer than normal weather at our regulated utilities, partially offset by the impact on earnings as a result of divestitures.
Temperatures across our Southeast service territory were significantly warmer than normal during the second quarter of 2019, including the warmest May in the last 50 years, resulting in $0.03 of benefit compared to last year and $0.07 of benefit versus normal. A detailed reconciliation of our reported and adjusted results is included in this morning's release and the earnings package.
Taking a look at customer growth. We added nearly 23,000 residential electric customers and over 14,000 residential natural gas customers across our regulated utilities in the first half of the year. These additions put us on track to meet our full year expectations for residential customer gains across our electric and gas franchises and are comparable to the growth we experienced in the same period last year. Customer growth continues to be driven primarily by strong job growth and population growth in our Southeast service territories.
Weather adjusted retail electric sales were down just over 1% year-over-year due to a combination of factors, including continued energy efficiency and technology advances across all customer segments and continued weakness in industrial sales.
Industrial sales particularly primary metals, chemicals and stone, clay and glass were down due to global trade concerns and a strong dollar's impact on trade, as well as changes in production levels and some timing. On a year-to-date basis, adjusted earnings per share were a $1.50 in 2009 with essentially no weather impact.
To be clear, weather on an aggregate basis has been normal for the year despite the warmer than normal second quarter period. Our estimate for the third quarter of 2019 is a $1.10 per share on adjusted basis with normal weather. We will assess our earnings guidance range for the full year after the third quarter.
Turning now to some updates on capital requirements. In June Southern Power successfully closed on its sale of the Nacogdoches Generating Facility to Austin Energy for $460 million. The sale of Plant Mankato to Xcel remains subject to Minnesota and North Dakota State Commission approvals and is expected to close this fall.
Year-to-date equity issuances from internal plans have resulted in proceeds of approximately $450 million which is higher than forecasted. Southern's equity needs for 2023 now stands at roughly $2 billion. While we have the capacity to fill our projected equity needs through our robust internal equity plans, we continue to evaluate all options to efficiently source equity. Financial stability and strong credit metrics provide significant benefits to our customers and investors and remain a top priority for us.
Before I turn the call back over to Tom, I'd like to give a brief update on our regulatory calendar for the remainder of the year. As we get [Technical Difficulty] to Atlanta Gas Light and Georgia Power filed base rate cases with the Georgia Public Service Commission in June, we expect that these Georgia proceedings, as well as the pending rate case for Nicor Gas in Illinois to conclude in late 2019. Mississippi Power is scheduled to file a base rate case with the Mississippi Public Service Commission in the fourth quarter of 2019. Lastly Georgia Power received a final ruling earlier in July on its Integrated Resource Plan and Tom will highlight a few of the outcomes in that proceeding.
Tom, I’ll turn the call back over to you.
Tom Fanning
Thanks, Drew. As Drew mentioned earlier this month the Georgia PSC approved the Georgia Powers 2019 Integrated Resource Plan or IRP in a 5-0 vote. Recall, Georgia Power files an IRP every three years and the improved plan outlines how the company will continue to deliver clean, safe, reliable and affordable energy to 2.6 million customers over the next 20 years.
The approved plan includes the addition of 2,260 megawatts of new renewable generation and the retirement of five - coal fired generation units totaling nearly 1,000 megawatts. As a result, the Georgia Power intends to grow its renewable generation portfolio by more than 72% to nearly 5,400 megawatts by 2024 increasing the company's total renewable capacity to 22%.
Georgia Power also received approval to own and operate 80 megawatts of battery energy storage systems which will help position the company as a leader in energy storage. In addition, Georgia Powers environmental compliance strategy was approved, including plans to close all 29 ash ponds. We believe these are constructive outcome that will benefit our customers on many levels in the years ahead.
In closing, I'd like to highlight a few newsworthy items of which we’re particularly proud. For the third year in a row, Georgia Power was ranked number one for customer satisfaction among large utilities in the south by J.D. Power in its 2019 Electric Utility Residential Customer Satisfaction Study.
Georgia Power achieved the highest score in its category based on multiple factors, including reliability, corporate citizenship, communications and customer service. Two of our natural gas utilities, Virginia Natural Gas and Chattanooga Gas were recently recognized as most trusted business partners in the utility industry by Cogent Syndicated and the alliance to save energy named Alabama Power as the 2019 star of efficiency for its smart neighborhood project outside of Birmingham.
In addition for the fourth consecutive year Southern Company was named among the top 50 companies for diversity by DiversityInc. Our long standing commitment to diversity and inclusion is embedded in our culture and allows us to better anticipate change and achieve success as we build the future of energy. I'm very proud of our team for these accomplishments.
Again, we are very pleased with our performance from both a financial and operational perspective. Through the first half of the year, we continue to see our regulated franchises operating on a high level and we are achieving key milestones in Vogtle. We remain focused on bringing Unit 3 and 4 online by their regulatory approved date of November 2021 and November 2022. We are committed to keeping you informed and look forward to providing another in-depth update at the end of the third quarter.
So thank you for joining us this morning. Operator, we're now ready to take questions.
Thank you. [Operator Instructions] Our first question comes from the line of Greg Gordon with Evercore ISI. Please proceed with your question.
Hey, Greg.
Morning, Tom. A couple of questions. Congratulations on continuing to see the type of productivity improvements that you need to be within the now sort of April to November timeframe in - on the Vogtle project. Can you can you comment. I know it only just came out in the last 24 to 36 hours on why you think the staff of the Georgia Commission in their review of your last filing is more sceptical of your ability to execute and where the dissonance might be between your cautious optimism and their scepticism?
Yeah, sure. Glad to do that. First of all, I think - I think it was reasonably a fair report. We respect those folks and you should know, everybody on the phone should know that the people that write that report, whether it's Dr. Jacobs or other key members of the staff sit in every meeting that we sit in virtually. So they're in the co-owners meetings and they're in there with Southern Nuclear management, with Bechtel, with me and Paul Bowers and Drew and all the team.
So number one, all the cards are on the table for everybody. Number two, I think one of the other important paragraphs you should read in that report is the first paragraph. And that's a very I think positive statement about the process that we're going through.
I think the third point is we certainly respect these people and they are certainly confident. But where we would find differences of opinion would really go to our belief in our own capability, when you think about the players I just mentioned, whether it is our own team building the plant, led by Glen Chick, who came from Browns Ferry that put a - completed a nuclear plant and know how to do this. That's the most recent example; our own expertise and look at the track record of success that we've been able to show since we took over the project from Westinghouse; look at Bechtel, they are by far the leading contractor for nuclear plants around the world. And you know I have a great relationship with Brendan Bechtel. In fact, weekend or two ago I was with not only Brendan but his dad Riley.
The team on site there, look I think we know how to build nuclear plants and I think there are certainly different approaches you could take, but we believe that our approach has been tested recently, not only at Browns Ferry but also in China and that we think everything we're doing is sound.
There are no secrets, there's no hidden cards. Everything that we're doing is open for discussion and it's not only us, its our co-owners and anybody - oh the NRC and everybody that looked in believes that our practices are sound. It's very reasonable that somebody could have a different opinion about that, but we believe that our conviction is well suited.
So I would say those general comments. I would say just other things that are important. And it really goes to how you look at the data. I spent a little bit of time in the script talking about this sawtooth or ramp up of effect. We believe that we are reasonably on track to do what we need to do on electrical work front.
It did start a little slower than probably we wanted, but that's not completely unexpected. Bechtel would describe that as their S-curve we call it sawtooth. But we believe now we're hitting the numbers we need to hit in terms of the electrical work front and if we sustain that and then we want to improve it a little better, we believe that we're reasonably on track to do it. We need to do to hit the schedule.
And so far the milestones are reflective of the aggressive site plan. We readily admit, the aggressive site plan is in fact aggressive, okay. But every time we beat 100,000 hours or every time we beat - we achieve a milestone consistent with the aggressive plan we build and maintain margin to the November in-service date and that is ultimately success. Greg I'm glad to go into anything further you'd like to, but I think those…
Not that’s extremely thorough. I appreciate it. Two more quick questions. One is just in the quarter you know, you’ve said that you had you know, that the hottest May in 50 years. And I know you said on a year-to-date basis things have sort of evened out.
But can you suss out how much usage and how much - how much of the - how much of the incremental earnings in the quarter whether it was usage or directly weather driven came from that weather event or is it sort of…
Sure…
[indiscernible] clear that you were able to carve that out?
Yeah, Greg. This is Drew. We actually put it in Slide 9, but the weather impact for the second quarter was about $0.03 relative to last year and about $0.07 relative to normal. But if you look at it over the course of the entire year, I think weather is actually down about a penny relative to our normal expectations for consumption.
As we look at the individual usage classes, you know, conservation and energy efficiency are pervasive trends particularly in residential and commercial and then on the industrial side, we did see a downtick of about 2% in total electricity sales. We think a good portion of it just really describes a general economy that's in a bit of a pause.
Trade skirmishes are sort of a vacuum to good capital deployment or a barrier to good capital deployment over the long term and a strong dollar in general with an economy that's about 25% dependent upon exports for its production really just signaled to us that we're seeing a little bit of weakening and that's – in that section of the economy.
Hey, Greg. Let me jump in here real quick. Let me correct them, I had a brain cramp. I don't know why, I was in a conversation this morning kind of getting ready for CNBC. I had Browns Ferry on my mind on another issue, the last completed one was Watts Bar. So anyway…
I don't think anybody would have caught that. But thank you.
Yeah. You bet…
Have a great morning, guys.
Yeah. Thank you, buddy. Appreciate it.
Our next question comes one of Julien Dumoulin-Smith with Bank of America Merrill Lynch. Please proceed with your question.
Hey. Good morning.
Julien, thanks for joining us.
Hey, thank you rather. Hey listen, I wanted to follow up a little bit on Greg's question if you could elaborate a little bit. I mean, clearly both you and staff talk about potentially - shall we say using up some of that contingency. Where and how would you kind of read into progress against that and confidence or really what variables or specific elements are going to be eating into that contingency. Is there any difference in opinion between you and staff on where you might be using that contingency or where the greatest risks are to that specific element? Then I got a follow up.
Yeah. Well, I mean, let me just start with the basic concept right? When we created the new estimate July a year ago, we put everything that we knew into the estimate and then we said let's create a contingency of some percent above that estimate.
And the contingency basically allows for things that you don't know in the current period if you have a reasonable expectation that you'll spend over time. To the extent we made the statement that we're not going to use contingency, we would have to reverse it.
At this point we believe that for everything we know we think there is still a reasonable likelihood that we will use contingency. Otherwise we'd have to reverse it. We don't think we're in a position to reverse that today.
Now, will we use contingency going forward? I think we probably will. That is the assessment that we must make in order to keep it on the books and keep it in place. Look we continually re-evaluate our cost position and we're very gratified as of the current period right now that we haven't touched contingency, we look at all the pluses and minuses. You must imagine that as a daily activity and we evaluate that against our own kind of reserves and our own kind of allowances for change.
So far we've been able to manage any of the pluses and minuses with cost today and what we know in the future with our own reserves on site, but we haven't touched contingency. My only caution is to people don't be surprised if and when we do. And it may be kind of lumpy and maybe you know, 50 million to 100 million or 150 million, there's still three years to go on both these projects. My only caution to people is our contingency is there for a reason.
And Julien, if I could sort of reintroduce a concept, that I have talked about a number of times and I think it's supported by the independent system monitors report. If we look at contingency as a percentage of our estimate to complete, we're maintaining a level that's perhaps in excess of 20% of that total estimate to complete. As Tom said, consumption of this in our view is probably certain the pace at which we do it is a little less certain. But nevertheless, if you measure us over a longer period of time, I think we'll take some great comfort in where we stand when we get to some point in the middle of next year.
And contingency can take a lot of different forms right? But let's focus on Unit 3 for a minute here. We're about a year away, round numbers, maybe a little more, to hot functional test and what that says is your five or six month away from loading fuel. And then you're six months away from having an in-service.
We are rapidly approaching, eliminating the uncertainties at least with respect to that unit, every month every quarter that we go by staying with schedule gives us more certainty that we'll be able to hit ultimately the November regulatory agreed upon process. So that's a big deal.
And as you know, hot functional test is essentially the completion of construction. That's Unit 3. These things are happening right now. I think I've mentioned on TV that we announced yesterday that we've sent out a contract to procure fuel. So these times are fast approaching, whether we're going to use contingency or not at least on Unit 3 is right in front of us. So we are right now making a whole lot of progress.
Nice. If I can follow back up on the Georgia IRP process and just all together understanding the CapEx budget. I know you guys have historically done solar and sort of followed up after the fact and reflecting that in your outlook. But how do you think about the cadence of reflecting the latest IRP developments here and how do you think about your own participation in subsequent RFPs that will come out now?
I'm sorry. Julien, what's the point of the question, is it how did we work with them on that, you want to me comment on that?
How do you think about reflecting the CapEx benefits from any further generation procurement here from the IRP?
I see what you're saying. Thank you. Yeah, we will - you know, as been our historical practice, we'll update CapEx probably the first - the end of the year call which will be end of January, 1st of February. So we're getting ready now.
But I would argue that the direction of CapEx associate with this IRP approval is probably up when you consider the ARO associated with the ash ponds, when you consider kind of the storage project. You know, the swing in that when its obviously solar. If you remember last year, I don't think Georgia Power won any of the new solar, but Southern Power did. And then later Southern Power came in and bought a lot of the development activity by other successful bidders, that also can be a swing in what CapEx looks like down the road. But that's a little hard to predict today.
Look, I'm glad you brought it up actually. If I can clarify it. With respect to the ARO and the Georgia piece and obviously looking forward to Alabama, how much of that is already reflected just versus what's incremental here, specially the ARO piece?
Yeah, if you look at the ARO it really is a 10 year obligation generally to make this environmental investment and about 40% of it is represented in our plan, something like that today, over the five year plan period. So if we look at the $38 billion that we think we will invest over the next five years, those investments are largely centered around modernization of the transmission distribution infrastructure and environmental - environmental investments.
I think your question is more around the modernization of the generating fleet or the movement of - into renewable generation, which we kind of view as being a post 2023 issue - 2023 being the plan you're about to post, as a second half plan year that would give some durability to our growth rate and total invested capital in total rate base.\
And there's some other kind of interesting ideas we introduced in the IRP that also could have a bearing here. One is that for the first time in my knowledge anyway in the history we had a section on resilience, and one of the ideas that we put in place is this notion of inactive reserve that is not retiring a coal plant per say, but taking it out of economic dispatch, preserving it as a matter of resilience in the event of a system emergency that could help in a whole variety of ways. Anyway, all those things have a bearing. We will certainly clarify that. But I - you know next year - but I think the general trend would be north of where we are.
Yeah. Got it. All right. I'll leave it there. Thank you guys very much.
Thank you my friend.
Our next question comes from line of Praful Mehta with Citigroup. Please proceed with your question.
Hello, Praful.
Thanks so much. Hi. How are you doing?
Terrific. Hope you're well?
Excellent, excellent. So thank you for all the answers so far. I guess just to clarify, on the contingency that you highlighted just wanted to understand as you pointed out that you want to keep it on there as a justification for keeping it in the plan. Could you at least give some color on what specifically you have put against the contingency right now that allows you to keep it in the plan?
It's just general uncertainty about the remaining work to be done and the schedule on part in which it will be done. You know, there's you know just to remind everybody to finish, I guess Unit 4 you're three years away, round number. So there is a lot that could happen between now and then.
And I think the lack of - the lack of clarity with what could happen, you know in a hope, what are they call the unknown unknowns could certainly have a bearing. You should know also this is also a difference of opinion a little bit in the report by the staff. And that's perfectly fine. We keep a risk register.
So what we do is we analyze the top you know, 10 kind of - it's actually bigger than that, but the top kind of 10 big things. And we like a subcontractor cost. And we look at how their performance has been with relation to construction startup testing. And we just continually reassess those. Its kinds of things that really go to our assessment about contingency.
The other thing that you should know, I mean, think about as you go through testing, it may be that some of the equipment you test doesn't work the way it should and going to need to rework it or it could have a schedule impact or who knows. But that's the reason why there's just enough uncertainty remaining that we keep the contingency in place. We are gratified. Make no mistake, we haven't hit it yet. But don't be surprised if we do in the future.
Got you. That’s super helpful color. Understood. Maybe secondly on comparable plans in China. I know that there has been some unplanned outages there. Any color that you have in terms of what could be the reason for that. And is there any kind of design issue that you're aware of that could become a problem for Vogtle as well?
Yeah, sure. Last question first. There is no design issue that we're aware of. Number two, there's been a lot of discussion about the RCP reactor coolant pump and you know, I think it's pretty clear the discussion around, we don't know the root cause effect. I think that reports coming out reasonably soon on site. But that really is a matter of discussion between the Chinese and Westinghouse.
But that has been the only significant outage and our sense is that they have equipment on site that they could have improved the speed of the recovery or whatever. But for whatever reason that's really for them to answer. That's just one of 16 RCPs on site, there is no to our knowledge there is no design or systemic issue that we're aware of.
Okay, great. Thanks and good to get that out of the way. So appreciate that. And then finally just quickly on the equity issuance timing, is there anything we should be thinking about around all the options and what are the options that you're thinking about and from a timing perspective how should we think about that as well?
Probably I think we've shown really good discipline in terms of capital raising over the last year and a year and a half, probably two years. We've been focused on making sure that any divestiture that we do or slimming down of our core business is accretive to what our expectations are for equity. You know, you've seen some activity in this period in particular with the sale of Nacogdoches and I think our pending sale of Mankato.
We've also done some streamlining across other parts of the business and recently sold the utility services business out of PowerSecure. We've discharged a very small container shipping lease program that was part of cleanup after the Nicore acquisition from 2011.
So really working through all of the options that we have to reduce the burden on share issuance. The programs that we've had to date, the internal plans of drip generate about $500 million per annum and in share count the options exercise which is another component of an internal plan have accelerated a bit because of share price appreciation over the last few months.
And so I'd just say that, as we look at all of the options available to us to satisfy the remaining $2 billion we just want to be as considerate from an investor perspective as we possibly can. Our route though is to meet our capital plan we can do it with simply using the internal plans that we have in place, all other options we would use would be only accretive to that plan.
Got it. Super helpful, guys. Thanks so much.
Thank you.
Our following question concern line of Ali Agha with SunTrust. Please proceed with your question.
Hello, Ali. Good morning.
Good morning. Morning, Tom, Drew. First question, Tom just wanted to come back to the staff report on Vogtle. Anything in there that that kind of surprised you and what do you make of the criticism they have on the approach that you all are taking. I think in their words you know, a premature focus on testing versus focusing on construction completion any thoughts there?
Yeah. Sure, absolutely. Not really. I mean, a lot of the points they raised have been raised in the past in DCMs and other things. I can remember some discussion about not enough attention paid to milestones and too much attention paid to hours worked. And I can remember commentary over the past that you know, we had this ramp up of ours and there was no concern about whether we could do it.
Well, in fact, we've demonstrated and I started saying that the last October's earnings call about how - you know don't listen to our rhetoric just watch and see if we can ramp up the hours, I am sure enough we have.
So I get concerned you know, and that's their job. They're the adversarial staff. And like I said we respect those people. That's what they're doing. They're pointing out issues. We're well aware of the issues, we all know the issue.
In terms of kind of the process, we think we have a really good balance on site right now of evaluating kind of the process of commodity work whether it's hours or material or whatever and focusing on milestones.
It's very easy to think about kind of how all hours are not created equal. For example, some hours when we go to these weekly things and that's why we tried to and I guess this was two earnings calls ago, maybe three, that we started saying to you guys we're giving you hours and we think that's instructive. But as we start down this new rebase lining it's important to think about milestones because not all hours are created equal. In other words, some of the hours that we're talking about have nothing to do with critical path. They are illustrative of our ability to put deploy labor and productive hours in place.
Let me just give you an example. We have now ramped up worked hours per week at around 188,000 hours per week, all we count are hours that accrue to productive work. So the delta between say 145 and 188, we believe it's headroom that allows us to increase productivity on site. Essentially this S-curve or sawtooth effect and get to where we want to be to 160,000 number. That's why we have some confidence.
This idea about deferring some work in order to start a milestone, we completely, we all understand, we talk about this a lot in these meetings that they attend, we attend, the NRC attend, Bechtel attends. This is a very intentional strategy of people that have built nuclear plants before.
And yeah, not all these hours are required in order to start a system test. But we think keeping to the aggressive schedule really helps us. In fact, some of the testing activities have already uncovered some benefits that will serve us well in the future in reducing hours. So sure, it's a balance, so we accept the point. But we think we're doing the right thing.
Got it. Secondly, just to clarify, the fact that you know you came in this quarter well above what you were budgeting for the quarter, was that all or primarily weather related. Given weather was so much better than normal or was there something else that caused you to come in so much better than your original expectation?
I think the underlying utilities are doing great. Let me just kind of start there. These folks you know, we've had - and not to throw at anybody else, but if you look at resilience issues around the United States, whether there's temporary blackouts or things like that. We've had a reasonably hot summer, particularly in a month where we didn’t expect it, May. The resilience of our system, the investments we've made over the years and we'll continue to make have proven to benefit our customers like nobody's business. And so, we're very happy I think with the operation of our system.
And let me just also say, we don't often talk about it on these earnings call, but things like our ability to deliver service, Georgia Power for example, leads in customer service and customer satisfaction, we think that is a wonderful indicator of support for the hard work our thousands of employees do every day.
The other thing I would say is recall this $0.80 per share that we did, did not include, I don't know $0.07 of divested earnings, Gulf Power doesn't include Puerto Rico that added considerably to last year. So on all fronts our franchise businesses are doing wonderfully well.
Okay. Last question. As you pointed out through the first half weather normalized sales are down about 1% or so. If I recall correctly, I think the budget for the year has been flat to up 1%. Are you re-looking at that or are you still confident you can get there?
No I think we are very confident with the projection that we laid out. I've have to look at whether normalization over a longer time period. We've had I think two exaggerated quarters in that - I think it was probably February where we were with - it was considerably warmer than normal and now May it was in opposite season considerably warmer than normal. And so these two things tend to have - serve an exaggerating effect on our estimates of weather adjusted normal sales. But still pretty confident given the strength of the underlying economies here, job growth, residential and migration that would be in the right range for the year.
We’re gratified with customer growth. The other thing I would just add, what we see in some of these results is timing, a onetime effect, like the industrial that being down 2%. We really think kind of going forward that’s a number more like 1%, absent these effects. So look it's very clear that we're in a little bit of a plateauing on the economy and I think that's why the Fed is kind of thinking about what they're doing.
But by the other token, our companies are managing expenses under Drew's leadership and the execution at the operating company level. We are delivering terrific results. Georgia Power for example, top quartile you know, O&M right now.
So we're able to accommodate whatever variances we see, be it weather or be it in organic sales.
Understood. Thank you.
Thank you, sir.
Our following question comes from the line of Michael Weinstein with Credit Suisse. Please proceed with your question.
Hey, Michael.
Hi, Tom. Hey, on the SPI Directs Performance Index slide, what's the reason for the uptick since May you know, when you look at that and how it's creeping up there? I'm just wondering what the - what's driving that?
Let me get to the slide. Oh yes. Obviously, it's 4th of July. We did hit our numbers on that week.
So you expect it to come back down.
Yeah, yeah.
Got you. All right. And on the ARO…
And Michael, just…
Go ahead.
Real quick, I'm sorry. If you heard in the script we talked about last three weeks. That was to exclude the 4th of July.
Got you.
And remember the statistic we're showing here is a four week average. So it's picking up 4th of July.
Right. Hey, on the IRP and the IRO, and also the rate case. How much flexibility do you have in spending on coal ash remediation going forward, given public comments so far on the rate case and the filing amounts and concerns that you know about how the rate filings was a larger amount, just wondering if there is flexibility in how you can spread out that spending over time?
Yes. So Drew, let's tag team on this because Drew's got this great stuff, but using executive privilege I am going to lead the away. Georgia hasn't had an increase since 2013, that was the increase they deferred, and now it's 2019. So when you think about the increase that Georgia Power is talking about, the frame of reference is kind of nine years. In other words, last six years no increase, three years looking forward. So think about the increase they're talking about in the context of nine years, okay.
And so what they've done in order to deliver results is manage O&M. They're now top quartile easily and some other things. You have some kind of interesting data points.
Well, to your point around the rate case, if you look at the impact the customer share of wallet and burden to bill rates have been basically unchanged over that eight or 10 year period with the rate increases have been proposed it's I think less than 1% in total over that.
Michael your question really related to - related partially to ARO, what its implications might be for rate. I would tell you that the $10 billion program that we have today is today's best estimate of how that investment will unfold. The chances of it being overly accurate today are slim. We will modify that plan as we proceed and so the timing of expenditure will change over the period, the total amount will change.
Recovery is the same feature which is we have a lot of flexibility and I think the Commission and Georgia Power are considering different ways for recovery that will reduce - ultimately reduce the burden on customers.
And I think Drew raises the right point there. There is a balance between what we must do and we have an agreed upon plan with the state EPD and the whole thing. So we have a what and then as Drew correctly points out, we have a how out of recovery. So that will be the subject of the rate case and we're certainly not going to get in front of that. So that will be worked out in a constructive manner I'm confident.
Got you. Okay. Thank you very much.
You bet. Thank you.
Our following question comes from the line of Michael Lapides with Goldman Sachs. Please proceed with your question.
Hey, Michael. How are you?
I'm fine Tom. Thanks for taking the question. Real quick. You're doing a lot of fleet transformation with all the renewables with the extra gigawatt of coal retirements. How are you thinking about, A, how this impacts the need for incremental transmission across the system. And B, when you think you'll start seeing similar fleet transformation and in your other large jurisdiction in Alabama?
Yeah. So that's a terrific question. In fact, part of the IRP, one of the reasons why we love our IRP process in the Southeast is, we are able to iterate around generation and transmission decisions, that's really difficult in the so-called organized markets.
In fact, included in some of the closures and potential flexibility in the future is in fact an iteration around some major transmission projects. For example, I know that whether we do it you know in the next three years or down the road, building some more transmission east of plant Bowen, which is kind of Northeast Georgia that we want to go east of there to bolster our system makes a lot of sense.
For years we have talked about transmission improvements along the bottom south of our system. So let's - we used to call it a southern highway, that it kind of shows increases from Mississippi across Alabama used to go into the Gulf. So the iteration around generation transmission - generation decisions and transmission is really important. What was the other part of your question?
Well, just Alabama, when do you see happening playing out - when do you see a sizable, because if you think about your fleet transformation so far it's been mostly Georgia. When do you see that playing out in Alabama if it all?
Well, so here's - Alabama has a different process than Georgia. Alabama did announce that they are going to retire a thousand megawatts of coal and they have been under a public process to procure more gas.
We think that they will undertake a process that may give more clarity by the end of this year. But that really is between Alabama and their commission. So you just stay tuned.
Okay. And then a little bit of a housekeeping one for Drew. Drew, it looks like the tax rate in the quarter was pretty low, if I just look at the financials in your - in your packet, like sub 15%. I'm just trying to think about - you know, how to think about the second half of the year in tax rates?
I think that I'll have to probably answer your question in more detail when we get into the boiler room. But the two biggest drivers I think probably were ITC amortizations and current period and tax impacts in the sale of subsidiaries. I don't think that our rate will be significantly different on a normalized base system what we experienced last year.
In fact, there was a gain on the Triton investment that had the biggest impact on our effective tax rate in the current period and we recorded some gain on investment tax credits from the sale of Nacogdoches. So a little bit modulated by the cleanup of the portfolio that we've been doing.
And I guess we've announced it really, but we did sell off another piece of business at PowerSecure. A utility services business.
That just helps sharpen our focus on that.
Got it, guys. I'll follow up offline. Thank you, Tom, Drew for responding.
Always great being with you. Thank you.
Our following question comes from the line of Sophie Karp with KeyBanc. Please proceed with your question.
Hey good morning. How are you?
Morning, guys. Congrats on the quarter and thank you for taking my question.
Oh, delighted.
I wanted to maybe switch gears a little bit and ask you about the Mississippi. It's been kind of quiet, but there's been some changes in the commission and you're going to go in for a rate case later this year. I guess, what are your expectations about how this jurisdiction is going to shape up going forward if any and so what are you seeing there on the ground?
Yeah, I think it's been quiet and that's good for everybody I think. You know, Mississippi continues to regain its footing after the plant Ratcliffe, Kemper County event. And you know, I would say since then we got the gas plant in place in a very constructive way.
So I would say - I would determine it really since then it's been very constructive. We look forward to a fair process and certainly we're not going to get in front of what's going to be filed and what they'll think about it. But I think it's been very good.
But your framework there has been in place for a really long time correct?
Oh, absolutely, gosh, believe it or not. The performance evaluation plan they modified over the years, but it was put in place about the time that I was CFO there, which goes back to 1993, I think is when I came there from Australia. So it's about that old 25 years.
Yeah. And should – do you also think that this kind of framework stays in place and maybe just the changes around the edges or should we...
Yeah. In fact, you know, what, you look around all of our three electric utilities have different processes and all of them are terrific. That performance evaluation plan is great. The RAC plan and Alabama has been great and the kind of three year process we go through Georgia has been great.
And when I say great here's what I mean. At the end of the day they produce terrific results for customers and look at it, we've got among the lowest prices in the United States. I think Georgia now has more than 15% better than the national average. Customer satisfaction is high. We're able to handle kind of very thorny issues together with our regulator to produce great business results, that helps everybody. So while each of these mechanisms are different each of them work well.
Got it. Thank you.
You bet.
Thanks, Sophie.
Our following question comes from line of Chris Turnure with JPMorgan. Please proceed with your question.
Hey, Christopher. How are you?
Good morning, Tom and Andrew. Just a modeling question for you following up on some of the prior ones on the quarter itself. Are there any items included in your adjusted EPS that we could consider not recurring for next year? And in particular on the power or the gas side?
In ex- items, I guess is your question. So ex-items were dominated by the gain on the sale of Mankato, Nacogdoches wholesale gas services are backed out. And then we had small charge for plants under construction which would be largely Kemper. Non-repeatable next year I think would probably be acquisition disposition integration impacts, but we will continue to back out wholesale services I think in the future.
Hey, Chris. I thought you were saying in our adjusted earnings were there anything onetime or...
Yeah. That's what I was driving at within the adjusted number.
Yeah. Not that I'm aware of. I mean, other than what we talk about to you is I mean, weather junk like that. But no…
No smaller gains on sales or anything in there?
And one time as we tend to push those off into the ex-portion that Drew was talking about.
Yeah, probably one of the bigger deltas relates to income we did have in ‘18 and didn't have a ‘19 which would be revenue from Puerto Rico. We did settle some small litigation in Southern Power about $12 million, so less than a penny, about a penny a share, but…
Nothing significant.
Nothing significant.
Okay. Great. And then one other question on Vogtle, among the others here I think you were successfully able to hire 400 people I think for the day shift in June and then your goal was to shift them over tonight. Any more recent commentary for your progress in the month of July?
Yeah. Well, here's the - yeah. Let me give you the breakdown on, remember as you point out and as we start adding people, most of that was going to go to the night shift. And in fact we've added a thousand people since the last call. And in fact, when you think about the percentage differences between where we were and where we are, I wanted to say we were, gosh 75, 25 day tonight. Now we're kind of 65, 45. So all of these additional personnel are going largely to the night shift. And so you know there is productivity issues and all that. But boy that's working well.
And just to give you a quick commentary, we're pretty well done on pipe fares. As we've got all that we need. Electricians we're on track. We have what we need today, we'll probably add a few more. But we're very happy with where we are on staffing.
Great. Thank you for the color.
You bet.
The following question comes from the line of Andrew Weisel with Scotia Howard Weil. Please proceed with your question.
Hey, Andrew. How are you?
Very good, thanks. Good morning.
Good morning.
A follow on question on the Georgia IRP around coal sales or coal retirements - excuse me. Obviously that was part of the package, but obviously also some other people wanted additional coal plant retirements. Could you explain the strategy behind keeping some of those other units like Bowen 1 and 2 for example and is that economics versus reliability or how should we think about the potential for additional coal plant retirements?
Yeah. So there again that’s well-defined regulatory process in which to evaluate that. But it really goes to two big things, economics and then reliability. It is very clear that other forms of generation, regulatory environment around coal and carbon and everything else, that there's a lot of pressure on any sort of carbon emitting type of generation, clearly coal. And so therefore coal will continue to be under pressure over time. You can't just shut those things down and we demonstrated some of that in the IRP.
When you think about Bowen 1 and 2 just for your example, it is lower in the dispatch curve than it has been over time, not because of cheap plentiful natural gas, it's continued to be pressure probably as we add renewables and a variety of other things and as we add nuclear. The notion of this inactive reserve taking it out of dispatch as a matter of resilience is a discussion point, right now. Nobody agreed to do that.
But I think given the notion of the increasing importance of resilience and let me be clear, IRPs are founded under decades long mathematical practices that deal with the cost of outages and reliability, resilience and reliability says this is how my system acts under normal conditions, including weather variances and normal outages and a variety of other things.
Resilience really goes to the idea of how my system operates under abnormal conditions, whether that's a hurricane or a snowstorm or a cyber attack or what have we had a major interruption in a gas pipeline. Are we thinking proactively skating to where the puck will be on ways to manage significant disruptions that we don't currently anticipate happening.
And so that is where we get into these ideas like standby, I mean I'm sorry, inactive reserve. These are very constructive conversations that we're having with the staff and with the commission. And really I'm trying to elevate that conversation nationally. These are important issues we need to deal with.
Okay. Thank you. If I could squeeze in one follow-up. On this third quarter guidance, will you remind me your practice? Does that assume normal weather or does that reflect the favorable hot July weather we have seen?
And then kind of as a follow-up to that for the full year, should we - I know you'll update guidance on the next quarterly call, but are there anything we should consider that might be an offset to the favorable weather? Or would it be fair to assume you're trending toward the high end of the guidance range?
Our guidance or expectation for the - our expectation for the third quarter does assume normal weather. I think that's the simplest answer and you know as we've seen great volatility month to month and projection versus actual I think that's probably our best process for prospective planning.
There's a joke upon this, I got to tell a joke. There’s a joke among the CFO. I used to be CFO, remember. There was a CFO of Mississippi Power and we go through these meetings where Drew just - they all work together and beat each other up about what the right numbers are.
And Frances Turnage, CFO of Mississippi Power one time said that all of our positive variances are temporary and all our negative variances are permanent and that's how she sets her numbers. But in general, Drew and team work really hard to get a good number for you guys.
And you know, it's just not an appropriate quarter for us to update our expectations today. Let's get through the summer. The bulk of the summer heating season and we'll be able to give you a really good sense of how we think the year is going to come out.
And you guys didn't ask a question, but I'll go ahead and answer the question. When Drew gives you the third quarter estimate that implies something for the fourth quarter. If you look historically we think we can handle that pretty easily.
Great. Thank you, guys.
You bet.
Our following question comes from the line of Charles Fishman with Morningstar Research. Please proceed with your question.
Hello, good morning. Thanks for joining us.
Hey, just one question on slide 16, generation mix. Tom, if we look out 10 years and let's assume natural gas stays cheap. If I look at the right hand pie chart, nuclear obviously up, renewables up, coal down. What happens in natural gas?
Yeah. Oh this is great stuff. So there is actually a lot of degrees of freedom in that question, right. So 10 years. But let me give you this. We have - in fact, this goes back to my time as COO. Oh so I'm telling old man stories now. This is 15 years ago, 20 years ago, but 15 years ago.
We started using probability weighted way to think about carbon prices or the cost of carbon. And we do essentially a three by three matrix of high medium and low gas prices, high medium and low coal, high medium and low cost of carbon. So when we do an IRP we actually have prices of carbon that go into the probability estimate and we come up with in probability terms a dominant solution, that comes up as the IRP.
The carbon prices we use our zero, $10 and $20 a tonne. It's very easy to manipulate that, manipulate meaning change it and put in new input that would say, what happens at $50 a tonne. And so we go through all sorts of stress analysis about that.
Here's kind of the big variances, my sense and this is my judgment today no guarantee, you're going to continue to see low cheap gas forever. I mean, that's why we bought gas and that's why gas has been a great solution for us.
So you're going to see gas migrate north, you're going to see renewables improve significantly, you're going to see nuclear with the addition of Vogtle 3 and 4 remain reasonably constant. And then over time you will see coal diminish. I think that's a matter of economics. It's a matter of a whole lot of thing. Now whether coal goes away from a capacity standpoint or just diminishes from an energy standpoint goes to these resiliency strategies I've been talking to.
So who knows? This is where we made the commitment, we were first out of the gate, I think to say low to no carbon. How natural gas continues to stay in the mix depends upon at least one or two big technology innovations that we're working on.
One deals with how are we going to manage the carbon atoms that come off hydrocarbon kind of looking fuel type. If we could continue to have success in capturing carbon and ultimately doing something positive with it then you'll see natural gas be really robust for a long period of time.
The other one is storage. If you succeed in storage beyond kind of the lithium ion technology we see today you may see a much bigger penetration of renewables. So those are kind of the big swing points.
Okay. Fascinating. Thank you.
Yes, sir.
Our following question comes from the line of Phil Covello with ExodusPoint. Please proceed with your question.
Thanks for joining us.
Hey, it's actually Andy.
Oh, Andy. How are you?
Hopefully you're still thankful.
Yeah, well you know, pretty much.
Just very, very quick numbers question. So just - so the $10 that you're giving for the third quarter, I guess the trailing 12 months would be like 285 because it was like $0.25 in the fourth quarter. So again you know, assuming normal weather, what drives the fourth quarter to like $0.40 or something like that? What are the drivers?
This is Drew. If you look at the last five years sort of the modern Southern era with gas, we've been sort of bimodal in our reported results something in the quarter to $0.50 range. And what has been modal is really whether in the third quarter and its impact ultimately on earned ROEs. And so as we move in - move through the third quarter we'll have a better sense of where we will be in terms of earn versus allowed.
In the fourth quarter we’ll either be sort of the supplement to a poor weather quarter in the third or it will be reflective of large reserves taken for customer refund in the fourth. And so I think that's kind of how we think about third - the interplay of third and fourth quarters. I think what we've set up is very consistent with our experience over the last four or five years.
In other words if we've essentially had very beneficial weather in the third quarter that produces over earnings. And therefore, we have less earnings in the fourth quarter.
So that’s what happened last…
And what you're seeing - and where we didn't have that kind of weather we tended to have less sharing and therefore better fourth quarter results. And Andy just to give you in ‘17 we earned $0.51 and in ‘15 we earned $0.44.
Okay. That's perfect answer. Thank you very much.
That will conclude today's question-and-answer session. Sir, are there any closing remarks.
And I promise not to talk about the greatest Tour de France in the last 10 years. You know, it's interesting this is a important period I think for me personally. This is my - the anniversary of my first earnings call with the company after I took over from the great Art Beattie, and I would expect a call from him this afternoon.
If I think about what our conversation was centered around last year really was whether or not completion of Vogtle 3 and 4 would occur. And I'm really sort of enjoy the fact that that we've moved on from that conversation I think because of structural improvements that we've put in ourselves, in terms of the commitment that we've made to you know advancing the construction. We've had major milestones met over the last year and we've converted a labour force largely from iron and concrete into pipe and to wire.
If I look at what's ahead of us, we've got a couple of major milestones that we want people to focus on. I think we get a little bit overly myopic in terms of hourly rates or Canadian visas and it's promising I think that we've moved on and think about major milestones and their turnover.
As we talk through this with investors, I think we're very open about the fact that we maintain reserves of both time and cost that we think will allow us to meet our expectations with the commission which ultimately is for completion in November of 21 and 22. And I think we're in good shape to meet those commitments. It's been a - I think a very important year in terms of the success of the company in advancing that effort.
Hey they only cherry I'll put on that one is this, you know, we said a year ago that 2019 would be an awfully important year. And if you look at the first half of this year, it's a great report card, lot of work ahead, nobody's counting any chickens at this point, but son of a gun you got to be happy with the first six months and we're happy with what we think lies ahead. So we'll keep working and hopefully we continue to deliver the good results that we have so far. Thanks everybody for joining us this morning and we'll see you soon. Take care.
Thank you, sir. Ladies and gentlemen, this concludes the Southern Company second quarter 2019 earnings call. You may now disconnect.