Good morning. My name is Marion. I will be your conference operator today. At this time, I would like to welcome everyone to The Southern Company’s Third 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. [Operator Instructions]. As a reminder, this conference is being recorded Wednesday, October 30, 2019. I will now like to turn the conference over to Mr. Scott Gammill, Investor Relations Director. Please go ahead, sir.

Thank you, Marion. Good morning, and welcome to Southern Company's third 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.

Good morning and thank you all for joining us. This morning, we reported strong earnings per share substantially above our estimate. Year-to-date earnings through September have also exceeded our expectations and the fourth quarter is off to a strong start for our electric utilities with unseasonably warm temperatures in early October. Drew will further discuss our earnings results and expectations in a few minutes. Before providing you with an update on our progress at the Vogtle site, I want to highlight our outstanding operational performance this quarter. We experienced record heat in the Southeast this summer, recording all-time September peak load days, four times during the month. Our electric system demonstrated resilience with record peak season generation in transmission performance, resulting in exceptional reliability for our customers. Importantly, even amid these conditions, a diverse field mix enabled Southern Company system to reduce our carbon emissions by approximately 35% compared to the strongest demand of 2007, our benchmark year for carbon emissions. Let's now turn to an update on Plant Vogtle Unit 3 and 4. The site continues to make progress as demonstrated by the achievement of several milestones during the quarter, including the start of integrated flushing activities. We remain focused on meeting the November 2021 and November 2022 regulatory approved in-service dates, and we continue to maintain an aggressive work plan on site as a tool to help position us to meet those dates. There is no change in our total estimated cost to complete the project. Last quarter, we discussed at length the contingency we established for the project in the second quarter of 2018. Recall the total amount we established is $800 million for the entire project of which Georgia Power’s share is $366 million. For the quarter, Georgia Power has allocated $30 million of its project contingency into the base project capital cost forecast. There are a host of factors both positive and negative that go into that analysis. But the biggest factor in allocating contingency was probably increased costs forecast related to craft attraction and retention. To give you context, contingency as a proportion of the estimate to complete is larger today than when it was established 15 months ago. We continue to believe that we have sufficient contingency to meet the budget associated with the November regulatory approved in-service dates. Overall, including engineering, procurement, and initial test plan activities, the entire project is approximately 81% complete with Unit 3 direct construction currently 77% complete. The project major milestones for 2019 have been achieved, or are expected to begin as planned later this year. We continue to successfully attract and retain craft labor. And currently, we believe, we have the resources necessary on site to support our aggressive work plan. Over the past several quarters, we have experienced periods of fluctuation and productivity around significant startup and construction activities. This variability has resulted in a sawtooth or S-curve shape in our performance charts, an effect we discussed on our last earnings call. In August, as we started our integrated flushing activities, we saw a similar effect on Unit 3’s productivity. Production levels have improved in recent weeks, and we are seeing the positive impact of a mature workforce with an increased ability to balance the needs of both construction and testing on site. The site has averaged nearly 150,000 earned hours over the past four weeks, with two recent weeks at about 160,000 hours, a record on the site. Cumulative CPI remains near last quarter’s levels, reflecting the construction and testing balance I just mentioned. On previous calls, we have focused on both Units 3 and 4 in the aggregate. At this point in the project, Unit 4 is progressing slightly ahead of its aggressive site plan. As you can see on Slide 7, Unit 3 construction is currently lagging its aggressive site plan. The primary driver is a backlog in the installation of electrical commodities and increased system turnover activity, trends we discussed last quarter. Southern Nuclear and Bechtel are implementing a productivity improvement plan to address the electrical backlog. Additionally, project leadership is utilizing specialized teams to focus on commodities installation and adds further enhanced night shift efficiency and has streamlined preparation for system turnovers. These initiatives have demonstrated initial success, as I have already noted, and further improvement is expected. With these actions, we believe there is sufficient flexibility and margin in future testing and startup activities to maintain Unit 3’s aggressive site plan milestone targets. To that end, we began the start of integrated flush activities for Unit 3 in August consistent with the aggressive site plan. Integrated flush is proceeding as we expected at over 60% complete and continues to support the start of open vessel testing later this year our next major milestone expected for 2019. Open vessel testing will continue through the first quarter of 2020 as we prepare for cold-hydro testing. Additionally, we expect to have the ability to test plant systems from the main control room before the end of the year. Each of these major milestones is important to the successful startup and operation of the plant and will lay the foundation for commercial operations. We continue to believe that working to an aggressive site plan is the right strategy in support of our primary goal of bringing Vogtle Unit 3 and 4 online by the regulatory approved November 2021 and 2022 in-service dates. This is a very exciting time for the Vogtle project. Within a year, we expect construction to be largely complete for Unit 3 and we expect to be preparing Unit 3 for fuel load. Consistent with past practice, we will continue to provide updates on our earnings calls and through the regulatory process as we move towards these major milestones. I will now turn the call over to Drew to cover our quarterly performance in greater detail.

Thanks, Tom and good morning, everyone. In the third quarter of 2019, we achieved earnings per share of $1.34 on an adjusted basis. That's $0.24 higher than the estimate we provided on our last call and $0.20 higher than the earnings per share on an adjusted basis reported in the third quarter of 2018. A detailed reconciliation of our report and adjusted results is included in this morning's release and earnings package. A key driver but not the only driver of our quarterly results compared to last year was warmer than normal weather at our regulated electric utilities. Temperatures across our Southeast service territory were significantly warmer than normal during the third quarter of 2019, including the warmest September in the last 50 years, resulting in $0.09 of benefit compared to last year and $0.15 of benefit versus normal. Emphasizing Tom's earlier remarks, our operational performance over this period of prolonged high temperatures was nothing short of extraordinary. Excluding the impact of weather, our $0.11 increase over the prior-year was primarily driven by higher revenues at our regulated utilities. The revenue increase reflects the impacts of Tax Reform and related changes in capital structure. You will recall that the majority of tax benefits accrued to customers and we retained a portion at our regulated utilities to maintain credit metrics within those entities. The increase in revenue also reflects other pricing effects and customer growth net of changes in customer usage. All of these factors more than offset the impact of divested entities. We've also been successful in mitigating inflation related to O&M expense as we operate more efficiently. Taking a look at customer growth, through September, we have added over 30,000 new residential electric customers and over 21,000 residential natural gas customers across the regulated utilities. 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 and population growth in our Southeast service territory. For the third quarter, weather-adjusted retail electric sales were down about 2% year-over-year versus last year due to a combination of factors including continued energy efficiency, technological advancements across all customer segments, and continued weaker Industrial sales. Industrial sales, particularly primary metals, petroleum, paper and textiles were down due to global trade concerns, as well as changes in production levels and demand response programs. These trends have persisted throughout 2019 with year-to-date electric sales down 1.7%. While the overall usage trend is negative year-over-year, it is consistent with our expectations. Weather normalization is also less precise in these extreme circumstances and we do not foresee a significant change either positive or negative in our service territories in the near-term. With adjusted earnings per share through September of $2.84, we expect to achieve full-year earnings at or slightly above the top-end of our guidance range of $3.10. Remember fourth quarter earnings can vary materially year-to-year due to sharing mechanisms at our regulated electric franchises that help mitigate the customer bill impacts related to extreme weather, a situation we have certainly seen to-date this year. Turning now to some updates on our capital requirements. In early August, Southern Company completed a $1.725 billion equity units offering when combined with our year-to-date equity issuance from internal plans to approximately $625 million and projected internal equity plan issuances through the end of 2019, this offering is expected to completely satisfy Southern Company’s total equity need through our five-year plan period. We do not plan to utilize our at the money equity or ATM programs issue shares, and in 2020, we expect to begin open market purchases to satisfy the dividend reinvestment plan. Financial stability and strong credit metrics remain main top priorities for us as they provide significant benefit to our customers and investors. Before I turn the call back over to Tom, I'd like to give you a brief update on our regulatory calendar. We started the year with a full slate of regulatory proceedings, some of which we recently concluded. Earlier this month, the Illinois Commerce Commission approved a $168 million annual base rate increase for Nicor Wet Gas including $65 million related to Nicor’s multi-year pipeline infrastructure replacement program already in rates under the investing in Illinois program. New rates also include a revenue decoupling mechanism for residential customers. This outcome is representative of a credit supportive Illinois regulatory environment and was in line with our expectations. Also, Virginia Natural Gas received approval to extend and expand its SAVE infrastructure replacement program with an estimated investment totaling $370 million through 2024. In Georgia, we're in the midst of a base rate case proceeding for both Atlanta Gas Light and Georgia Power. We expect these proceedings to conclude in the fourth quarter of this year. Further, Mississippi Power expects to file a base rate case with the Mississippi PSC before the end of the year and we'll keep you posted as that schedule evolves. In addition to these proceedings, in September, Alabama Power filed with the Alabama Public Service Commission, a comprehensive proposal that addresses how the company is strategically planning to meet customer demand during the winter peak. Alabama Power’s proposal include 2,400 megawatts of new generation capacity, comprised of long-term power purchase agreements, acquisitions, and new constructions with an expected capital investment totaling approximately $1.1 billion. The proposed generation mix is diverse calling for 1,800 megawatts of new gas fired capacity, 400 megawatts of solar projects with paired energy storage systems, and 200 megawatts of distributed energy and demand side management. We expect all regulatory approvals to be obtained by the end of the third quarter 2020. Tom, I will now turn the call back over to you.

Thanks Drew. As Drew outlined, we are very busy on the regulatory front. We've demonstrated over the course of many decades that we're able to effectively manage our business to bring clean, safe, reliable, and affordable energy to our customers who are at the center of everything we do. Our regulators share these same broad goals and we are confident that the ongoing proceedings will result in outcomes that support these objectives. Now, before we move to your questions, I'd like to highlight a few accomplishments that are in recognition for the company during the quarter. Both Alabama Power and Georgia Power were named a top U.S. utility for economic development by Site Selection Magazine. Economic development has always been a priority for our regulated utilities. And we successfully partner with state and community organizations to bring companies, jobs, and investment to the states where we operate each year. In addition, Southern Company's been acknowledged for our leadership on transparency and disclosure. South Company’s 2019 proxy statement was named the number one proxy statement in the country in the inaugural U.S. Transparency Awards, sponsored by Labrador, a global communications firm specializing in regulated disclosure documents. We were also ranked third in the U.S. for overall disclosure by the same organization. These are all outstanding accomplishments and I am proud of our team. As we move towards the end of the year, we're very pleased with our performance from both a financial and operational perspective and believe we are well-positioned to deliver adjusted earnings per share for the full-year at or above the top of our guidance range. We've also completed our expected equity need through 2023. In the fourth quarter, we should have clarity on some of our remaining regulatory proceedings and will be in communication with you as these cases conclude. We have achieved several key milestones at Vogtle and remain focused on bringing Unit 3 and 4 online by their regulatory approved dates of November 2021 and November 2022. Thank you for joining us this morning. Operator, we are now ready to take questions.

Thank you. [Operator Instructions]. The first question comes from the line of Greg Gordon from Evercore ISI. Please go ahead.

Greg, good morning.

Good morning. Congrats on a great quarter.

Thanks.

Couple of questions. I know you gave us a lot of information with regard to Vogtle and we're all as pleased to hear that it's going well, but can you just clarify what you're -- what you mean when you say that for all intents and purposes now the contingency is a larger piece of the overall budget. Is that because you're doing better on sort of the expected base cost of building the plant before contingency?

Yes, sure, Greg. I think Drew's got some great details here. I'll let him fill in the blanks on real details. That is a pretty easy concept, when you put contingency in place as we talked about last quarter it's because it's an unknown cost that you expect to spend, it’s part of the official budget of the plant. As you go through, really we do this thing all the time, but just imagine every month we add-up all the positives and negatives around cost, and all the different components of the plant and we net those out. Until this quarter, we have never had the negatives kind of outweigh the positives in evaluating the contingency balance. This minor amount of $30 million that we just pulled out now represent costs that really relate to compensation that we put in place to attract and retain especially electrical workers on the site. When you take into account how much contingency as a percent of remaining cost was in place, when we set up the budget, even accounting for the draw of $30 million against the contingency account, the percentage left for remaining construction is higher now than it was when we established contingency in the first place. Drew has some even better data there?

Well, certainly difficult to add to that. I’ll just say that the estimate to complete is the denominator and the contingency is the numerator. And so that ratio is now larger than when we started. I think the only other feature that's worth noting is that, if you think about time in our contingency and time, we're 25 months out from hot functional testing. So we're pretty close to construction completion --

On both units.

…for the delivery of Unit 3. I'm sorry, 13 months. If you look at our delivery expectation, which is November of 2021, that's 25 months. If you look at the amount of time and contingency that we maintain today, it's greater than nearly 25%. So six months over those denominators. So I think both the cost factor and the time factor give us some comfort that we can deliver within the regulatory expectation.

So Drew big as a breadbox, 24%, 25% now. What was it when we established contingency round numbers?

Little less than 20%.

Yes. So you can see as a percent of total cost contingency now is higher as a percent, even accounting for the $30 million than it was when we established it. And that really is a function of time.

Thanks. I've got two more questions. One is -- it's also a little bit remarkable in that despite the record demand you had this summer but you were able to keep O&M flat in the quarter. So I mean, that's actually, to me like a pretty positive marker, can you talk to how you were able to keep O&M under control, even though you had such high levels of demand?

Let me give some kudos. Drew used to be CEO of AGL Resources, and before that he was the CFO. And when we looked in the diagnostics of that company as we are making the acquisition, he and his team there had a great track record of thinking about effective ways to deploy O&M, technology, et cetera. So he's come over, Beth Reese has come over with a key player and they're applying a lot of those concepts here.

It’s -- cost control is, needs to be a long-term discipline, I would say that the vast majority of what's occurring here is not smart people moving over, but really the hard work of folks that operate underlying utilities. And as folks move into rate cases, they have to be very focused on cost control; we have to remember that $1 of cost saved allows $8 worth of capital investment and improvement in modernization of our systems. And so rather than looking for large belt tightening exercise, I think the right discipline for us is to be prudent about managing inflations within our business. And that's what we're trying to demonstrate this year.

And then there's just been the big technology substitutions. You may recall that I think we led the world in local offices for so many years. And that was really important to us. But with the advent of technology, I think Georgia Power has demonstrated that without the local offices, they can still increase customer touch through technology, by over 400%. So we can remove some physical costs, improve technology and improve customer service all at the same time.

Fantastic. My final question is milestones on the Georgia Power rate case, if we're going to get to a point where we can settle it, what's the usual cadence of that and how do you get to an answer that hopefully retains the integrity of the ROE band that you're currently put at risk/opportunity for achieving in light of the initial staff position being such a low ROE number.

Yes. And Greg, you've been following us for 100 years, I think and so many of you on the phone have as well. Yes, look we've had this three-year rate process, the accounting order process in place in Georgia, since 1995. And I think every three years since 1995, we've gone through this process. The staff does what the staff does, and they'll - it's funny, we kind of went back and looked at prior iterations of these rate cases, what they've done in terms of their recommendation is not all that different than what they've done in the past. Look, let the process continue, typically in the past I think we've reached an agreement right before the Christmas holidays, I expect that will be the case this time.

Thanks guys, great quarter, congrats.

The next question comes from the line of Michael Weinstein from Credit Suisse. Please go ahead.

Michael, how are you?

Hi, good morning. I'm doing good, how are you doing?

Terrific.

Glad to hear. Hey, could you talk a little bit more about the low or the negative weather normalized sales growth on the electric territories? And whether that -- you think that that's kind of something that's maybe shaping up for the future as well or is this something that's only affecting this year, maybe next year?

Yes, I'm going to turn this over to Drew in a second. I'm going to offer my comment. If you look across the board, I always like to take kind of a mega look at this. When we saw these numbers, we said part of this is an adjustment for weather normal with the extreme weather we had, those adjustments are always subject to second guessing. The other one, if you remember, and Mike, you’re around go back to 2018, we had surprisingly high increases in retail sales. And in fact, I just have the numbers in front of me, for the same period for 2018, we were 1.7% up, this year we were negative 2.7%. In terms of residential, we were 1.9% up this time we were 1.9% down essentially flat over two years. Commercial, we were 1.1% up here a little bit down; Industrial we were 2.3% up now we’re 3.3% down. My view is if you take a longer view, these sales are kind of within the range of expectations. There's a whole lot going on right now also in terms of the Industrial economy. One of the things I always love to talk about is Industrial development, economic development, always kind of consider that the headlights. As we talk about a lot, capital investment, long-term investment, loves calm waters; they love nice stable environments in which to invest. While our economic development projects are about the same, or maybe 5% less year-over-year, but still a good number, the amount of long-term capital associated with our economic development backlog is down a lot around a half and the jobs associated with that are down a lot about a half. And you get into these arguments. Well, is this a function of the Fed, is it trade policy, is it -- I really think that long-term investment on the part of our customers is taking a breather. It's kind of plateaued out a bit really as a function of the trade issue going on the skirmish, whatever you want to call it. When we pass new tax law, when we had the advent of smarter regulation, there was an enormous breath of oxygen in the economy and we took off. My sense is pending the resolution of the trade skirmishes and maybe even the election year in 2020, I think we have the ability of sustained economy going forward or not, we'll see.

It's probably the only thing I'd add is, the way we plan long-term or have been planning in the more recent term for sales growth has been around an expectation that our customer accounts particularly residential would grow by about 1% a year. We offset that with the expectation that efficiencies will be persistent and that will lose, used for customer at about the same rate, maybe something a little bit less. This quarter actually this year-to-date, we’re down about 1.7% in total sales across all three customer classes. And I don't know if we've detailed them for you in the slides, but it's effectively nine-tenths in residential, 1.7% in commercial and about 2.5% in Industrial. This weather normalization is something that we have to construct internally; it is based on linear regression to be completely nerdy about it. And we've moved into non-linear portions of weather experience, which just means that we've hit some extremes. And some, I'm pretty certain that what we're seeing is maybe just a little bit of dissociation from our curves and not so much a result. If you look at last year, we saw about a 1.4% increase in retail sales through the third quarter that probably had the same sort of feature in that, maybe averaging these two years gives us a better indication of what's happening in our economy. Residential and commercial in particular, I think we're probably just seeing normal or expected declines in these areas. In the Industrial segment, probably since the fourth quarter of last year, we have seen Industrial production which doesn't have sort of a weather feature, migrate a bit down over the past maybe four or five quarters, as Tom said, probably due to a little bit of uncertainty and some trade headwinds. But we also have to remember that these are off of pretty significant highs in terms of levels of production at the end of 2018. And so these are just trends that we're monitoring. I would suggest that we look maybe more toward full-year, weather usage as normalization will become a bit more normalized, and that'll help us get a better understanding of how we're budgeting for next year.

Hey, one last comment following-in Drew's nerdy comments. As I was with the Fed for so many years, one of the things I love to look at is essentially the first derivative of change. And the momentum statistics in other words, evaluating how the numbers were changing over time also indicate it’s kind of plateauing. I don't know when this will resolve itself trading, the trade wars or whether it's the Election, but of the top 10 industrial sectors, year-over-year, you've seen about five of them go negative. So there is negative momentum. About three of them are flat, and about two of them are positive. And the two that are positive, are just less negative year-over-year. So I think all that data serves to underscore the fact that we are in a bit of a pause. And I think the pause can be resolved. So we'll see.

Okay, one last question. Could you just go over maybe what your future plans are at Southern Power? Are there going to be more asset sales coming or we kind of settle down at this point?

Well, we've always been in the posture of recycling capital. I think if you look at our track record, broadly from an M&A standpoint, we bought well, and we've sold well. And we always look for opportunistic ways to improve shareholder value. What is it we reallocate about $500 million a year, that's way off of where we were? We had then about a $1.5 billion allocation a year, we've cut that now by two-thirds down to $500 million. But you want to know something? A lot of that is a function of the market. We really see a tremendous amount of competition in the market with shorter terms on we love long-term bilateral contracts, those are getting shorter, and the margins are getting narrower. So when we look at the balance of capital allocation, I think, going forward for the next, I don't know three to five years, we're 93-plus-percent allocating to our core franchise businesses. We think on a risk adjusted data that's more attractive in the so-called certainly the organized markets or even the renewables markets right now. We'll keep our eye on it. But that's our posture.

Yes, Michael, it's fair to say, a lot of the work that we did last year was simplification of that business structure. And so we tried to get rid of assets that weren't gas assets that were not within our core service territory. Some of those things that we did around wind and solar were optimization of capital deployments, but not outright sale of assets. I think more importantly, we've just recently announced the purchase of Skookumchuck which is a wind generating asset; we're still very interested in investment in renewables. But as Tom said, we're going to be focused on the risk adjusted returns on those investments and be very careful of -- about what meets our threshold.

And it's just narrower than it was.

[Operator Instructions]. The next question comes from the line of Julien Dumoulin-Smith from Bank of America. Please go ahead. Julien Dumoulin-Smith: Hey good morning.

Hey Julien, how are you? Julien Dumoulin-Smith: Great, thank you. Hey, so just wanted to follow-up on a couple little details here. First up, as you think about where you're tracking in terms of dates here, just want to be extra clear heard your commentary about Unit 4, how that's going fairly well. How do you think about the main date for Unit 3 here? Just want to clarify here, given all your more constructive commentary?

Yes, the site continues to work towards the aggressive plan. We have always characterized the main schedules, both for Unit 3 and 4 as aggressive. Okay, we think that is the right way to run the site. Steve Kuczynski, the CEO of our Nuclear business, Glen Chick, the guy that really runs the project day-to-day, believe that’s still achievable. It is aggressive and we remain committed to that kind of work plan on site. I always want to remind people, our regulatory approved dates are November. And I think I've been famous for saying this in the past. If we hit those dates, we hit anything before that Ticker Tape parade time. But we think this approach of keeping an aggressive posture on sites avails us margin to achieve ultimately our regulatory approved dates. Julien Dumoulin-Smith: Got it. And I want to understand a little bit more on the contingency. So it sounds like the $30 million here the small utilization is more for construction and some of the higher costs to keep the qualified individuals around. But when I think about contingency conceptually here, as we pivot a little bit, should we think about that principally being allocated towards some of these in-service criteria and achieving those on time and on budget. And then even within that, can you clarify how are you thinking about these in-service criteria? Which of these processes or ITAAC should we be following or asking you or paying attention to most closely as best you see it?

Well, let me hit ITAAC first. I can remember geez three or four years ago, as we talked through this thing, we had ITAACs out there as one of the big risks. Now, let me underscore this. ITAAC must be done before we fuel-load okay, so it must be done. But I would say the work of the team in conjunction with the NRC over the years has brought that into a less risky posture. In other words, I believe we have a sound plan working with our regulator to achieve those milestones. So when I think about the top 10 risks on the project, I don't think ITAACs are there right now. I think we see our way through, we're making great progress. You may remember, we started a concept called UIS. But essentially, ITAAC that are complete except for the results of a test that has been very effective in reducing the byways of testing that must be done. So, I guess the other comment I would just make and I guess this goes to the contingency question. When we set that estimate in place, I guess it was July of 2018 that included for the whole project of $800 million contingency. There were actually buckets of contingency elsewhere like Bechtel has their own, we have our own. This is the one that we've called out specifically. And this is where the $30 million applies, Georgia Power dollars alone. And we call also that when we made this draw this $30 million, this is an evaluation, not of current period, but expected future period costs. So it is all the costs that we know about right now through the completion of the project that resulted in a $30 million draw. So I think we're in good shape, if that answered your question. Julien Dumoulin-Smith: Or maybe clarify that, you're using this for construction and labor costs, but with respect to some of these in-service criteria, and just achieving those milestones, you feel pretty good. You haven't used any contingency. But should we be expecting updates on contingency to be principally focused on the in-service or the construction side of this, if one can buy anything?

I mean there's buckets everywhere. And so when we did the $800 million plus everything else I mentioned that, Bechtel may have or we may have in our hip pocket somewhere. That includes a schedule that concludes in November and includes all known future costs through November, okay.

I think the only couple components I would add are that when we do a re-estimate of costs, it is a mark to completion of both facilities. And so we're estimating what we think it will take to complete both Units 3 and 4. And so this is not just a feature for the unit in the near, the Unit 3 in the near-term. In the end, though, Julien, money, time is money. And so a lot of contingency as we progress will be related to the amount of time, it will take to complete the project. That's -- I don't know that there are any expectations that there are system components that wind-up being more expensive than estimated.

The only thing I would reinforce though, is when we set that budget, that budget was set for November. So to the extent you finish sooner than November, you get pickups. That saves money.

The next question comes from the line of Praful Mehta from Citigroup. Please go ahead.

Hello Praful, thank you for joining us.

Yes, great call and great quarter. So congratulations. Just had a couple of quick questions, maybe just touching on Vogtle again, as you decide on trying to hit the November deadline and you have additional money to spend maybe to hit that earlier deadline versus allowing it to slip to November or it guess hit the November deadline. How do you choose on the cost side like are you looking to invest more to hit the earlier deadline the May deadline? Are you willing to allow the November deadline or target to kind of get to that and conserve on the cost side?

Well, it's any and all right, Drew said it a second ago, time is money. When you think about the hotel costs of personnel on the site, and the work that must be done. To the extent you're able to improve schedule, it takes a lot of cost to exceed the cost of time. So it's pretty much a dominant solution. If we can advance the calendar, if we can -- that's why we keep an aggressive site plan from that. That overwhelms generally speaking, the cost that we incur to do that. We always make an evaluation of that point however. In other words, we're not going to do anything stupid in terms of cost, just to achieve schedule. We always balance that. But I'll just tell you, the math is pretty compelling. If you can achieve schedule performance that does a lot for cost performance, and we believe that is prudent behavior.

Got you. It makes sense, that's helpful and then maybe on the weather normalized sales, again just touching on that given you have all the CapEx plans and Alabama Power’s investment as well. Do you think there's any implication on that load growth concern in terms of what that could do to bills given investment cycles and what you have going on with Alabama Power?

I think that's why we've got to focus on our cost structure. I think we -- mentioned it earlier, but $1 of cost savings permits $8 worth of capital investment. Alabama in particular, I think is proposing a resource mix that's important for meeting their winter peaking and makes pretty progressive strides in terms of the environmental content of what they're generating with. And so and ultimately I think will reduce total costs if you look at the O&M costs structure around coal fired generation. So what we're really trying to do is minimize in total, the impact on customer bills over time, but still have good investment in modernization. I suppose your question was, will lack of customer growth cycle it, it certainly makes it easier if you're -- if the underlying is growing but I don't think it probably reduces from our expectations.

Yes as me and Drew sit here and we sit in the management council meetings at Southern, the objective is no rate change as a result of capital investment. In other words as we increased revenue requirements, we must take commensurate revenue requirements out in our O&M cost structure. The idea keeping rates flat as we transition the generating fleet or invest to improve reliability and resilience.

Got you. Super helpful. And just a clean-up question, the income taxes in the third quarter, was the effective tax rate lower than previous and any particular driver on that tax rate?

No, I think more the third quarter of last year was a little bit anomalous, we had to make the assumption that we weren't going to utilize all of the film tax credits that we've purchased at one of the subsidiaries and so the difference really is a little bit unnatural in that regard.

Hey, probably one more thing, somebody just warned me and I said, yes, that's probably right. Georgia Power recalled in its rate case deferred any rate action three years ago. And so if you think about where Georgia is, holy smokes, this rate case really covered essentially nine years of investment. So that's a whole lot. The formulation I gave you to have no rate change in the future as a design criteria as you were referencing in terms of the CapEx going forward, transitioning the fleet and building resilience. The design criteria is to make O&M adjustments that compensate and produced no rate increase to customers. That's the design.

The next question comes from the line of Shahriar Pourreza from Guggenheim Partners. Please go ahead.

Shahriar, how are you?

Good. Good morning, guys. How are you doing?

Great.

So most of the questions were answered. It's very comprehensive. Just one follow-up around the retail sales and sort of the comments around more of the industrial activity. We've seen similar weakness reported by some of your other peers, right. But what turns out is, is the rate structure of the customers are I guess more fixed versus volumetric. So the EPS impact for deceleration in volumes is diminished. Do you have a sense on sort of the industrial customers and how we should think about their rate structure volumetric versus fixed. And I guess what I'm trying to get a sense on is if you see a prolonged weakness and you don't see a recovering industrial activity and sort of the global macro concerns are more prolonged, is there -- do you see an impact to fundamentals over the longer-term, right. So like, obviously, short-term, it's within your plan, but I'm just trying to get a sense on what the sensitivity is to Industrial weakness?

Well, from a corporate perspective, a 1% change in Industrial sales was about $16 million pre-tax and so pretty small impact. The Southeast generally uses Industrial customer rate design as a way to promote economic development and bring jobs to the region. So we're significantly less sensitive to it. I've probably created too much of a sensitivity to this factor in this question because we did have some demand side management programs that that worked productively in the period to make sure that we didn't have to curtail any needed delivery to customers and that we had, so we had good reliability to commercial and residential customers. And so that that will impact some of the sales figures as well. When we look at full-year though, I think we'll find that we're probably near our expectation which is around 1.5%, maybe 2% reduction in industrial demand in total.

Yes, and just to add to that, I think Georgia Power was the first and big -- probably remains the biggest in terms of RTP, real time pricing. That recall sends a price signal to customers and customers on their own can react to it or not, in other words, if they're making more money by driving through a peak period will be good for them. If they want to shut down during a high cost period, they can take that as well. So these are customer driven demand side management kind of issues. This is nothing we do demand. We have the biggest program, I bet you in the United States, something like I think 40% to 50% of our Industrial and commercial load is subject to real time pricing. Over the year provides terrific value to our customer.

Right, okay. So just to summarize if there is weakness in Industrial activity worse than sort of what your internal plan assumes, we should not assume that there's -- there would be a deceleration in your growth trajectory or fundamentals just given the fact that it’s not that sensitive. Okay.

The next question comes from the line of Stephen Byrd from Morgan Stanley. Please go ahead.

Hello Stephen, thanks for coming in.

Congrats on a good quarter.

Thank you.

Lot of questions have been addressed. I just wanted to touch on equipment testing at Vogtle, apart from the latest CCM just the status of overall testing, but any further color on where you stand with equipment testing, any lessons learned along the way, or just any further color on testing the equipment that's at the site?

Yes, thanks for that question. What was it? Maybe a call ago or two calls ago, there was a lot of conversation about the wisdom of early testing, does it cost a lot, does it reduce productivity, create the S-Curve et cetera. I think our posture has been to test as early as we could, even for partial systems. And we think that we have found the issues early and have been able to handle them in a very successful way. Also, as we test early, we can bring lessons learned to other parts of the plant and to Unit 4, we think that's really, really helpful. It reduces risk. It assists in our ITAAC completions. And just to tell you for Unit 3, we think our civil testing is now for construction is well over 90%, mechanical, over 77% and electrical testing on Unit 3 is at 50%. So this testing process we're going through right now is exactly what we want to have happened. And here's the other thing that really also goes to the sawtooth or the S-curve effect. When we enter into an integrated flush, we start testing and we want to find problems. Part of testing is to identify where your weak spots may be as soon as you can, so that you can address them and have a successful completion of a milestone, ultimately. And we think that is really going well. As our testing organization has started out, we have found now over time, that their efforts have matured and they're more effective at testing the procedures, the deployment; the coordination with construction has all been getting better over time. I think our recent hours work kind of indicate that as well. This whole program while it has been the subject of some conversation has served us very well.

That's really great color. And my next question is very, very broad, but I'm just thinking about your generation mix overall and the evolution of Solar Economics. And looking at your Plant Daniel in Georgia maybe just think about it, as you think about your generation mix and just the evolution of renewables economics do you see any potential changes you would want to make to your generation mix over time or you sort of generally happy with your current resource planning on that?

Well, so we do that we started this actually, when I was COO, we do a probability weighted kind of integrated resource plan, where we take different shots of different assumptions and probability weight them. In other words, we look at the cost of carbon. We already do that inside our math for our integrated resource plan. So we say there's no carbon price, and then there's $10, $20. We're now evaluating carbon costs prices as high as $50. We look at high medium low gas prices, coal prices, all kinds of things. And within all that scenario analysis, we come up with what we think are dominant solutions. Those dominant solutions manifest themselves in an evolution of where the best generation resources are and because we're not in a so-called organized market. In an integrated market, you can iterate around generation solutions and transmission solutions, okay. The other big thing I'm kind of nerding out now also, but I'll be -- I cover this quick is our reserve margin assumptions really change based on the penetration of renewables. The most important renewable resource for us and the Southeast is solar. We have pretty good resources, it's very cloudy here. But solar makes sense. We just don't have the kind of wind flows that support widespread wind generation. Our wind is imported through long-haul transmission systems, mostly from right now Kansas and Oklahoma. Okay, we go through this analysis and we develop optimal solutions over the next 20 to 30 years at both transmission and generation. And we do this in conjunction with each of our states so that this is a well-known process. As politics change, say for example, someone in a new administration wants to start a carbon tax, or there are different environmental costs associated with coal that we've seen over time. We certainly take those things into account. And so what we have is essentially a series of options-based solutions, where we can move the fleet. In general, what you find right now is Southern is between now and 2050, a much bigger share as you get towards the end date of renewables, that will mostly be solar. We will see a continued importance of gas at some point, very high carbon prices; you would see gas with carbon capture. Over time because of these costs, we see coal diminishing and we see a constant share of nuclear. The big swing in how these resources may follow depends upon technology investment, particularly in the realm of storage and the cost of carbon capture. You know that the objective function here is to provide low cost reliable electricity for the benefit of customers. And we have said low to no carbon by 2050. That low to no delta is really going to be spoken for by the advancement of technology, carbon capture, and storage. So we'll see. But that's the broad brush answer.

The next question comes from the line of Sophie Karp from KeyBanc. Please go ahead.

Hello Sophie.

Hey guys, good morning. Congrats on the quarter.

Thanks.

Couple of questions if I may. First, I wanted to clarify and going back to Vogtle, I guess the SPI that you keep saying it needs to reach 1.5 in the next nine months, in order to be in line with the regulatory deadline and I guess looking at the VCM filing testimony last week, and just it's been built tracking below that. So far does it need to average at 1.5 or does it need to reach that number or does it mean that you are kind of eaten into that six months buffer you have like can you clarify that a little bit?

Sure. Yes, look, I think you were just reading it opposite. In other words, we like a low SPI number, okay. What we would say by that 1.5 would be -- we would have to average that going forward in order to hit November. To the extent we're below that number as we are right now, I guess cumulative 1.03%, Unit 3, 1.01%, Unit 4, 0.96%. Remember, we said Unit 4 is tracking slightly ahead of the aggressive plan, that's indicated by a number less than one, one would essentially say you're on the aggressive plan, okay?

Got it.

So the fact that we're below is goodness, that's where you want to be.

Got it. So you would want to be average no more than that, basically?

Yes, you want to be less than something over 1.5.

Got it. And then maybe a little bit of color on Mississippi as we have more visibility on who the nominees are for the commission. So how do you expect the regulatory climate there to shape up after the election and is that affecting your time and decision that gets in the rate case filing, do you plan to go after they have the election?

We don't try to time elections or try to guess who's going to win. We think this company again; you go back to my history I'm in my 39th year for heaven's sake. We go through political swings all the time. Our regulatory plans, our service to customers, our notion of reliability is something that transcends politics and must be long-term. We always start with long-term answers first, and we work like dogs to make the short-term results be beneficial to investors. So we're going to file the rate case independent of any assessment of politics. And I think really, since Kemper, we've been treated really well in Mississippi; we think we've been treated fairly. We expect that to continue, no matter who's in office.

Our next question comes from Andrew Weisel from Scotia Howard Weil. Please go ahead.

Hey, Andrew.

Hey, good morning everybody.

Good morning.

First question -- first question on financing. Can you talk a little bit about the decision to issue the equity units in August as opposed to the prior plan of using internal programs or even a block or more traditional equity forward? And just to clarify, when you say that the equity unit satisfy your needs to the five-year period, does that assume you will or will not use the full contingency for nuclear construction?

Well, I guess, taking them in two pieces. I'll start with the second one first. It does assume that we use contingency that's embedded in the way we accounted for the cost re-estimation last summer and our expectations for construction. Although, I would say that the Delta is somewhat immaterial to the corporation in total. We will do $8 billion to $9 billion worth of CapEx every year for the next number of years or $38 billion or $39 billion over the plan period. And Vogtle represents only $3 billion or $4 billion of that in aggregate. Your first question was related to the equity units offering which was a mandatory convertible preferred security that we issued in August. It had a number of features that I think drew us there, but not the least of which is that we are quite bullish or comfortable that we will complete the nuclear construction within the regulatory window. And we thought that issuing units that convert after the first unit goes into service is probably to our benefit. We think this share price has a bit of room to regain round to historical trading levels and that instrument allowed us to share in any upside and so we will literally share an upside through the high 60s, maybe low 70s in terms of its conversion when it does convert in August of 2022.

Okay. And let me just offer my own commercial here. I can tell you this; this instrument was debated a lot internally. We think it was absolutely the right decision. But the math to me is pretty compelling for the future. And there's no promises here. I can't say whatever. But when you think about Southern Company and people are already making bets, I think, in our stock price. When you hear about Southern Company ex-Vogtle, there's no question in my mind, this company's been trading kind of on par recently, we should trade at a premium. So think about what a couple more turns may mean to the stock price and our P/E ratio. And recall we're in a period in Georgia Regulatory framework where essentially our ROEs coming out of Georgia look flattish. That's part of the rate design we had when we had the thing approved recently. As we clear these assets to in-service, the trajectory of earning increases significantly. I think you've all done your own modeling. When you think about a healthier P/E ratio, and you think about a much faster trajectory of EPS stock prices could be significant above this. We thought, though taking risk off the table, and at these attractive levels, made a whole lot of sense for us, and just took another issue of overhang off the stock.

Yes, the only thing I'd add, just to be clear, we do not plan to utilize the ATM program at all throughout our plan period. And we thought it was an important signal to equity investors that we were complete in our equity issuance and the instrument that you're describing allowed us to do that.

Great thanks, a lot of good detail there. And just to clarify this slide set that you will be issuing new shares for incentive compensation, what ballpark would be the annual need for that?

Let me -- I don't want to give you a halfway answer. So let us handle that maybe in a call after we can give you an absolute number, we'll keep -- we will issue shares under the drift for balance of year, there are still some options that are open to be exercised, where we don't control the timing. And there'll be some modest issuance relative to the total shareholder base related to executive compensation but I can't -- I can't offhand give you a number with much accuracy.

Not a problem, I will follow-up offline. Then just one last one, if I may, regarding the Alabama Power IRP or other petitions to certification, am I right that the $1.1 billion to the new gas plants and other capacity is incremental to the size of your CapEx plan that you previously laid out. And it still would be set that to the upside when you roll the plant forward with the fourth quarter results or would you de-prioritize spending either in that state or other states for things like affordability or the balance sheet or whatever else?

No, we do think it's incremental to our five-year plan. And we're comfortable that we can handle it within our expected cash generation capitalization goals.

Our next question comes from the line of Augustina [indiscernible] from Mizuho Securities. Please go ahead.

Augustina, thanks for joining us.

Thank you. Just wanted to clarify one thing, so around the time when the baseline review was filed. Basically, I think there were identified like a total of 1.4 billion contingency, which basically consisted of $800 million cost contingency and $600 million of schedule contingency. So just wanted to understand if those $600 million are still unallocated?

Well, they're allocated the schedule assuming we hit November.

Okay, perfect.

To the extent you finish sooner than November, you wouldn't need any of that.

Exactly. Yes, okay, perfect. And then one other thing, if you just -- if you could just talk a little bit about what would be the top three risks for Vogtle going forward?

Well, that's a good one. So we think about that a lot. The limited to three is always fun. But here's what I would say. Top three risks are going to be probably hitting our milestones. I know we've put out hours, but milestones are the big deal and it’s not just when we begin. It's when we finish. And did we run into the testing program where we had some equipment failure where we had some issues that we just don't expect that could prolong the successful test of any particular milestone. We know of nothing right now that would suggest that but I would say that is a risk. Another risk will be just kind of maintaining the kind of recent productivity that we have had now, we are building margins. There’s a wisdom on site of keeping an aggressive site plan gives us margin to November. And we want to preserve that as much as we can. We went through a very tough summer where it was very hot, hard working conditions, the thought to the fact of new work fronts being open, new people coming in. Can we maintain the kind of productivity improvements that we have seen recently, the last couple of weeks 160,000 last four weeks about 150,000? That's really good performance. Can we maintain it? I guess that's the last thing. And then -- and then I think just before fuel-load, that is going to be awfully important. Do we wrap up everything that even beyond hot functional test is non-critical path, I would say those three, people will argue about that. But I think that's it. I think that's a fair summation.

Perfect. Thank you so much.

Let me just say, most of that translates with schedule; there are cost elements to that. That's probably it.

The next question comes from the line of Ali Agha from SunTrust. Please go ahead.

Ali, always great to have you.

Thanks Tom, good morning. Good morning, Drew.

Good morning.

Just a couple of things to clarify. One I wanted to go back, you ended up getting or earning $0.24 above what you have budgeted for the quarter. And I know you mentioned the weather as a factor but can you flush that out? Let me know what else came in better than expected and are these 2019 issues or some of them actually go into the future years, we should think about as positives as we're looking at, earnings in 2020 and beyond?

So weather was certainly the single largest factor sort of $0.09 of the positive variance. The two things that were different than our expectation were levels of operations and maintenance expense. And so we were able to control to a greater degree than where we had budgeted. And then revenue related to real time pricing. The system lambda, the system average cost was actually quite low through the time period, but there was some congestion that led to a slightly higher rate signaling to some industrial customers.

And so Drew is that at least the non-weather piece, should we think that that could continue the O&M and even maybe pricing as we’re looking at 2020 and beyond?

Certainly things that we're working on, our RTP, real time pricing is more a function of the condition in the period. And so it's not something we view as being persistent. And let me just correct weather is $0.15 greater than expectation, although it's only $0.09 higher than where we were year-to-year.

Got it. And then secondly on Vogtle, Tom, if there was to be a change in either cost or schedule versus the way you're budgeting it right now, is the VCM the forum where you would give us an update, or would it be in some other fashion or forum?

I mean, Ali, it was significant; we do an 8-K. I mean it really just depends on the magnitude.

I see, okay. And then lastly, can you just remind us as you’re looking forward now, 2019 obviously is coming in well above what you were expecting at the beginning of the year. But can you just recalibrate for us the longer-term growth aspirations, the EPS growth aspirations that you're looking at? And what's the base from which you're looking at that growth?

Yes it was 4% to 6% --

Off of 287 which was our 2018 guidance.

Yes. And even with this kind of base that we're in right now with Georgia, we're well within that cone. And when you start to clear these units into rate base, the trajectory really takes off. So it's 4% to 6% and of course, next year, we'll update all that. But we're well within what we said.

And I think Tom, you said you could hit 4% to 6% every year, or is it like a cumulative growth rate?

It's kind of cumulative growth rate off of 2000, whatever it is 2018.

But we do expect to hit within that 4% to 6% range in each year --

Yes.

Off of 287 base, if you think about that as a cone of growth emanating from 287 will be within that band through the plan period is the expectation.

Our last question comes from Michael Lapides with Goldman Sachs. Please go ahead.

Hey guys, thanks for taking my call and congrats Tom and guys on a good quarter. I have a question, there was something in the Georgia Power rate case testimony that stood out a little bit, which was one or two of the intervenors, I forget which one made commentary about instead of having coal ash spend run through rate base albeit on expedited amortization schedule. Actually seeing if it could get securitized that that would be better for the rate payor for the customer in terms of the bill impact, just curious for your thoughts on that whether it’s even buyable under Georgia Statute and if not is there a mechanism or a method that would make sense to do stuff?

Yes, well let me give a couple comments. Number one, that idea whether it's a good idea or not will require legislation in Georgia, we don't have such a thing. The other thing was I would also go back to the IRP discussion where this issue was considered and approved on in the IRP. But let the process workout and let the commission and the company and all the intervenors come to a successful conclusion, we think we will be treated well there.

Got it. Okay. Thanks, Tom. Just housekeeping question for 2018 numbers for in the release for things like O&M et cetera, that includes or excludes the businesses sold in the last 12 to 18 months meaning last year’s. I'm just looking at O&M; it actually shows it’s down more than $100 million. I wanted to make sure that was apples-to-apples.

The 2018 figure includes the O&M for the businesses that were owned in those years.

Okay. Can you -- I forget, you may have done it and if I missed it my apologies. Can you quantify what the O&M change would have been without those business so like-for-like?

About flat I guess is the right way to think about it, but we can give you some detail.

So instead of a decrease it would be flat.

Yes, okay.

And that's how we characterize I think the O&M for the call here. And Drew, kind of big, big plan is to eat inflation every year.

And that will conclude today's question-and-answer session. Sir, are there any closing remarks?

Well, just want to thank everybody for joining us. This is an awfully exciting time for us all. And I know we all get focused on Vogtle 3 and 4. But the thing I want to reinforce is the thousands of people at Southern that are making this business home that even despite these really extreme loads we had, really through the summer, and even into October, there was one day very early October, where we do a system-weighted temperature. That system-weighted temperature in October was 91 degrees. This is a time we are normally hitting outage season and you're taking a lot of resources out of play. The system responded beautifully, the transmission people, the generation people, and we proved our flexibility and resilience in this kind of extreme condition. We continue to serve customers well. By all front this company is hitting all cylinders right now. So I know we all get excited and focused on Vogtle, I know I am. But I want you to know that the rest of the business is doing great. Thank you for your followership and look forward to talking with you soon. Take care.

Thank you, sir. And ladies and gentlemen, this concludes The Southern Company third quarter 2019 earnings call. You may now disconnect.