The Southern Company (NYSE:SO) Q3 2023 Earnings Call Transcript

The Southern Company (NYSE:SO) Q3 2023 Earnings Call Transcript November 2, 2023

The Southern Company beats earnings expectations. Reported EPS is $1.42, expectations were $1.32.

Operator: Good afternoon. My name is Dina, and I will be your conference operator today. At this time, I would like to welcome everyone to The Southern Company Third Quarter 2023 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 November 2, 2023. I would now like to turn the conference call over to Mr. Scott Gammill, Vice President, Investor Relations and Treasurer. Please go ahead, sir.

Scott Gammill: Thank you, Dina. Good afternoon, and welcome to The Southern Company’s Third Quarter 2023 Earnings Call. Joining me today are Chris Womack, President and Chief Executive Officer of The Southern Company; and Dan Tucker, 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 our Form 10-K, Form 10-Q and subsequent filings. In addition, we’ll 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 Chris.

Chris Womack: Thank you, Scott. Good afternoon and thank you for joining us this afternoon. Our premier state-regulated electric and gas utilities and Southern Power continued to perform well during the third quarter. Plant Vogtle Unit 3 has continued to operate at 100% react to power since being declared in service July 31, and we expect to deliver on our adjusted financial targets for 2023. Before Dan provides an overview of our financial results, I’d like to provide an update on several announcements since our last call. First, we continue to see economic growth across our Southeast service territories. We are excited about the important role our utilities play and attracted new jobs and investment to our states and communities and are proud of the recent recognition for those efforts as Alabama Power and Georgia Power will each named a top utility for economic development by Site Selection magazine.

With Georgia Power’s recognition representing the 25th consecutive year for this honor. Last Friday, Georgia Power filed an update to its integrated resource plan. Economic development in Georgia has accelerated over the past couple of years and is contributing to extraordinary projected electricity usage growth, which is significantly larger than historic levels. Electric transportation, manufacturing and its supporting supplier base have been major contributors to the state’s success along with new data centers to support increased computing power needs and the growing digital economy. With this 2023 IRP update, Georgia Power is proposing additional investments into Georgia’s energy future to provide economical energy solutions that should benefit our customers and communities for generations to come.

Building upon the plan approved in Georgia Power’s 2022 IRP, the 2023 IRP update seeks to continue the utilization of a diversified approach to help ensure resilience, reliability and flexibility on behalf of customers, and Georgia Power has requested that the Georgia Public Service Commission evaluate this update by the end of April 2024. In late September, Southern Power announced the acquisition of the 150-megawatt South Cheyenne Solar facility in Wyoming and the 200-megawatt Millers Branch solar facility in Texas. Commercial operation of the facilities is expected in 2024 and 2025, respectively. These projects represent Southern Power’s 29th and 30th solar facilities, which are the newest additions to a portfolio of 5,500 megawatts of carbon-free generating capacity.

Consistent with the project in Southern Power’s existing portfolio, these new projects include long-term contracts and counterparties with strong credit support. Additionally, Alabama Power’s Barry Unit 8 was successfully placed in service yesterday on schedule and on budget. This 720-megawatt combined cycle unit is expected to be one of the most efficient natural gas plants in the country. Consistent with the proposed resource plan in Georgia Power’s 2023 IRP update, we believe we are well positioned to continue applying our expertise and experience in constructing new natural gas and renewable generating units to serve our region’s growing needs. Last week, we announced a memorandum of understanding between Southern Company and the U.S. General Services Administration to develop carbon-free electricity solutions for federal facilities across our Southeast service territory.

The agreement documents our intent to collaborate on development of a road map that when executed will lead to federal agencies buying more carbon-free electricity in the region. We view this exciting partnership as another important contribution towards Southern Company’s goal of reaching net zero by 2050. And finally, last Wednesday, we issued our annual sustainability summary highlighting the great progress that we made as we continue to advance clean energy, lead through innovation, invest in our people and serve and elevate the communities that we have the privilege to serve. We have worked with our states, customer groups, communities, regulators, policymakers and other stakeholders to develop strategic solutions to deliver clean, safe, reliable and affordable energy to serve our growing economies.

Dan, I’ll now turn the call over to you for a financial update.

Dan Tucker: Thanks, Chris, and good afternoon, everyone. For the third quarter of 2023, our adjusted earnings were $1.42 per share, $0.12 higher than our estimate — $0.11 higher than last year. The primary drivers of our performance compared to last year were warmer than normal weather conditions, changes in rates and pricing and lower income taxes and O&M expenses, somewhat offset by higher depreciation and amortization. For the nine months ended September 30, 2023, our adjusted earnings per share were $3.01 compared to adjusted earnings per share of $3.35 for the same period in 2022. A detailed reconciliation of our reported and adjusted results as compared to 2022 is included in today’s release and earnings package. For the nine months ended September 30, 2023, adjusted earnings per share are $0.34 below the same period a year ago, with the extremely mild weather conditions we experienced in the Southeast during the first six months of 2023, representing a major factor in how this year has developed.

While weather conditions continue to present risk to our fourth quarter results, we project to achieve our full year adjusted earnings near the middle of our guidance range of $3.55 to $3.65 per share. Our adjusted estimate for the fourth quarter is $0.59 per share, which implies an estimated full year result of $3.60 on an adjusted basis. Turning now to electricity sales in the economy, year-to-date 2023 weather-normal retail electricity sales were approximately 0.5% lower than sales levels for the first nine months of 2022. Year-to-date, we have added approximately 35,000 electric customers and 19,000 gas customers, trends which continue to outpace pre-pandemic levels. Strong commercial usage was offset by a return to office dynamic and residential sales as the relationship between these two customer groups appears to have largely reached pre-pandemic status.

Lower industrial sales continued to be driven by weakness in the chemical, paper and housing-related sectors. More broadly, our service territories are in a period of industrial transition particularly as it pertains to manufacturing. Historically, significant industries such as paper and chemicals are making way for the manufacturing of solar panels, batteries, airplanes and electric automobiles. As Chris mentioned earlier, during 2023, we have continued to see an extraordinary level of economic development activity within our service territories. While we will provide formal updates to our outlook during our fourth quarter earnings call in February, we did want to highlight the magnitude of potential change we are seeing in electricity sales growth.

Recall, our previous forecast assumed annual electricity sales growth of 0% to 1%. Factoring in the power needs of these new, highly data-centric businesses and manufacturing facilities, electricity sales are likely to have an annual growth rate closer to a mid- to high single-digit range over the next five years. While there is likely to be significant incremental capital investment required to serve this level of economic development activity, we expect both existing and new customers to recognize economic benefits from this growth. Chris, I’ll now turn the call back over to you.

Chris Womack: Thank you, Dan. Before taking your questions, I’d first like to provide a brief update on our progress at Vogtle Units 3 and 4. Since successfully achieving commercial operations at the end of July, Unit 3 has performed well, delivering nearly 2.5 million megawatt hours of reliable carbon-free energy to the citizens of Georgia. On Unit 4, following fuel load and during start-up and preoperational testing, we discovered a motor fault in one of the four reactor coolant pumps, necessitating a full replacement of the pump with one from our spare parts inventory. We have successfully cleared the path in which the existing reactor coolant pump will be removed and expect to begin that activity in the coming days. Many preoperational activities continue along a parallel path with the pump replacement, including coatings, insight containment and preparation of the turbine for power ascension testing.

After successful installation of the spare pump, we will recommence with start-up in preoperational testing with a projected in-service date during the first quarter of 2024. Also, in late August as part of the Vogtle 3 and 4 prudence process, Georgia Power filed an application with the Georgia Public Service Commission to adjust rates to include reasonable and prudent Vogtle Unit 3 and 4 cost. Related to this application, the Georgia Public Service Commission public interest advocacy staff filed a stipulated agreement among Georgia Power and several other intervenors, which is intended to constructively resolve all issues regarding reasonableness, prudence and cost recovery for the remaining Vogtle 3 and 4 costs, not already in base rates.

The Georgia Public Service Commission is expected to vote on this matter on December 19. Again, thank you all for joining us this afternoon and for your interest in Southern Company. Operator, we are now ready to take questions.

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Q&A Session

Operator: [Operator Instructions] Our first question is coming from the line of Carly Davenport with Goldman Sachs. Please go ahead.

Carly Davenport: Maybe just to start to pick up on your comments on Vogtle. I guess, first, just any expectations at this point in terms of the actual process of replacing the reactor coolant pump when you’d expect to get that wrapped? And kind of talk a little bit about maybe what gives you confidence still in that 1Q 2024 time line. And any factors that you’re watching that could accelerate or decelerate that time line?

Chris Womack: Carly, again, thanks for your questions. We look at the pumps at Unit 3, I mean, the four pumps are running as designed. And as we’ve seen this from Sanmen in China, so we’ve seen this experience in terms of replacement. So, we think we have a good path to replacing the pump. And so, we just feel good about the process that we’ve identified that is in place for removal and then replacing the spare pump. So, we feel very confident about the process and where we are with the pump replacement process at this time.

Carly Davenport: Great. And then maybe just shifting to sort of some of the capital opportunities that Daniel alluded to facilitate this load growth that you’re expecting to see across your territory, I guess, in the context of the interest rate environment, how are you thinking about managing financing the CapEx required to support that growth? And how you’d expect to balance between debt and equity going forward.

Dan Tucker: Yes, Carly, it’s a great question. And look, just order of magnitude, we’ll provide specific guidance in February. But I think as we sit here today on the very front end of this IRP update process, we do see pretty substantial potential increases. And potentially, we’re talking billions of dollars where our current five-year plan for capital is $43 billion. I think we easily see a plan that translates to something north of $45 billion, and it’s really a question of how much higher than $45 billion once we get to February and kind of lay that out. And I say all that continuing to be conservative about including any owned renewables. We absolutely across all of our electric service territories expect to own renewables over the forecast horizon.

But we’re going to wait until there’s better line of sight on those individual projects to include those. So getting to your question in terms of financing, we’ve been very clear about our credit objectives. And I think our profile is positioned to be differentiated, and it’s our objective over the long term to preserve that differentiated profile. And so that will mean the potential for maybe turning on our equity plans. We’re fortunate to have one of the largest, if not the largest drips in the industry. We can generate between $350 million and $400 million a year just through those. And then we always keep on the shelf and at the market program just to have flexibility. So, we will absolutely do what we need to do to preserve the credit profile in terms of the balance of how that’s financed.

I think it’s still a fraction of any incremental capital that translates to equity. Again, I mentioned billions of capital and hundreds of millions of potential equity through the drip. I think that will be sufficient to maintain where we want to be.

Carly Davenport: Great. If I could just sneak one follow-up on that point, Dan. Do you have any — are there any targets that you have on the level of parent debt that you’d like to hold going forward?

Dan Tucker: I think where we sit today, Carly, just kind of on an unadjusted basis, if you will, so not trying to factor in equity credit or content for any particular securities. We’re a little south just of 30% overall. I think as the business grows, we don’t really intend to grow that percentage. So, the absolute quantum of debt may increase over time, but the proportion of parent debt to the rest of our debt will remain about the same, I think.

Operator: Our next question is coming from the line of Shar Pourreza with Guggenheim Partners. Please go ahead.

Shar Pourreza: Just a quick follow-up from the prior question. I guess, the opportunity set is pretty material, Dan, you’re obviously highlighting it could be in the billions. I guess, how do we think about that opportunity set in relation to your 5% to 7%? So is this a scenario where it’s accretive to growth or could be accretive to growth? Or is this sort of an extended runway scenario?

Dan Tucker: Yes. Look, Shar, it’s a great question. It’s the right question. But Chris and I have been out speaking to the investment community for months well in advance of this filing with the Georgia Commission coming together and acknowledging that whether it’s owned renewables, whether it’s the kind of economic development growth that we — and activity we’ve been seeing, potential for more capital has been lingering out there. But what we’ve both been very clear about is it’s not our objective to raise the growth rate as a result of that. What this opportunity presents itself as is an opportunity to strengthen the profile of the growth rate to potentially sustain it longer term. And again, the important governor on all of this is really two factors: One, we’re focused on the long term here.

We’re not trying to have some temporarily higher growth rate in the short term. And more importantly, number two, is customer affordability, making sure that we maintain a profile from a customer perspective that preserves the constructive regulatory environments, we’re fortunate to have. The other great benefit of everything that we’re seeing and the fundamentals that Chris and I are so excited about is this level of sales growth. That, in and of itself, will provide an opportunity to mitigate the affordability equation.

Chris Womack: And Shar, one thing I’d add. I mean, you know us very well, you know our process. I mean we will kind of give you that ’24 guidance in February of next year. I mean, so now we are looking at the headwinds, the tailwinds kind of where we are in terms of — I mean, the cards that we have and what’s in front of us, and we’ll update and give you that guidance in ’24. But I’d tell you, I mean, on the iconic development front, there are just a lot of exciting opportunities. We’ve got headwinds of interest rates, but we look forward to giving you that update in our call in ’24 in February.

Shar Pourreza: Just, Chris, thanks for kind of bringing that up a little bit just on — just, I guess, on the parent level maturities, it’s somewhat sizable over the next few years. So maybe can you just provide a little bit of the interest rate sensitivities, and I guess, how to manage those pressures, especially as we’re thinking about ’24 and I think you prior guided to right around that 395 to 415 range. So how do you manage that if you have a sensitivity there you can provide?

Dan Tucker: Yes. Look, Shar, just like we did this year, we’re going to kind of be thoughtful, creative, somewhat aggressive in terms of how we manage that. You saw us do the convert earlier this year that really mitigated the interest impact. We’ll do everything kind of at our disposal to execute in a way that keeps rates as low as possible. I think what everyone is likely stepping back in the industry and saying is, look, we all knew interest rates were higher, and this sense of higher for longer as you sit here today, it’s probably the longer piece that we all thought was perhaps not as long as what we’re seeing as we sit here. But I think it’s all consistent. And for us, kind of mitigated by this tremendous windfall of economic development activity we have.

In terms of sensitivities, look, if you think about kind of a 50 basis point sensitivity around interest rates as we move forward, think with every incremental year, it’s basically another an incremental penny of potential EPS plus or minus for that 50 basis points of interest rate sensitivity. And we’re not interest rate forecasters. We’re just basically using kind of public forecasts that are out there in terms of our planning.

Shar Pourreza: Okay. Perfect. That was all I had. I appreciate it. Thanks for the color and see you about in a week.

Operator: Our next question is coming from the line of David Arcaro with Morgan Stanley. Please go ahead.

David Arcaro: Maybe starting on the load growth side of things first. When do you think you’ll start to see that coming through in the quarter? I guess, the actual weather-normal sales were down over the last 12 months kind of a similar experience. So when do you think that inflection kind of comes to start to point the underlying electric load growth getting towards that upper single-digit level?

Chris Womack: I think as we lay out the plan and what the needs are, probably in the ’26 time frame, I think, we’ll see some of this play out could be as late as ’25. I mean as plants begin and they’ve got to be constructed. They’ve got to go online. So yes, we look at late ’25, the early ’26 time frame. I think before you will see this kind of show up in those increased sales?

Dan Tucker: Yes. When you hear us talk about economic development activity and announcements, Dave, typically, that is three, four, five years from announcement time for facilities to get built, to get staffed to get trained and operating at a capacity that’s meaningful to our load.

David Arcaro: Yes, got it. That’s helpful color and context there. And then — was just wondering if you could maybe elaborate a little bit on the pump issue on Unit 4. Does this look — are there any indications that it could be a design issue with the pumps has this happened at other AP1000 units? Or does this look like it could just be a one-off here?

Chris Womack: I think it’s a little premature to say. I mean once we get it out, I mean, we’ll get it back to the manufacturer to see actually what happened and we’ll learn from that. But right now, our focus is on removal of the pump and then replacing it with a spare and then moving toward the process of putting the unit in service. So — but yes, I mean, we’ll take a hard look at, I mean what happened to the pump and we’ll repair it and move forward.

Operator: Our next question is coming from the line of Julian Dumoulin-Smith with Bank of America. Please go ahead.

Julien Dumoulin-Smith: Indeed, likewise, Chris. Look, let’s talk about the upside CapEx just a little bit further here, if you don’t mind. I keep bothering you on this here. Let’s talk about first Alabama. To what extent is that going to be ripe for 4Q? And just also, how do you think about the ownership angle there as you think going forward, 2.6 gigs, I think that’s over six years, not trivial there as well. When you were talking about billions of upside, was that inclusive of that LMM opportunity? Or is that upside to the upside if you want to use that service?

Dan Tucker: It’s upside to the upside, Julien. So again, and I mentioned this earlier, we’re going to continue to be conservative on owned renewables that we absolutely have an expectation that will become part of the mix we’re not going to forecast it until we have better line of sight on individual projects. And in Alabama, those will largely be tied to individual customer stories. When it comes to this economic development activity, while I think kind of the tip of the spear sit here today is what’s happening in Georgia, there’s a lot of momentum across the rest of our electric service territory for opportunities like this.

Julien Dumoulin-Smith: Got it. Excellent. And just to clarify that, Alabama, that would be to the extent of which they’re more directly negotiated here with customers that would be presumably entirely an ownership opportunity and then just to clarify Carly’s question a little bit further, the FFO to debt piece of this, you’re thinking about targeting like a flat level here, even pro forma for the DRIP. It’s not like you’re leaning into the balance sheet by only turning on the DRIP. It’s that inclusive of that incremental capital, you’ll still hit a fairly flat level, if you will?

Dan Tucker: Yes. So on the first part, Julien, in terms of the mix of ownership — and this is going to be true for all of our electric service territories. It will be a mix. We expect to own a meaningful amount, but there is likely to be third-party PPAs in the mix here, just like there has historically. So, that’s the reason we’re not including anything forecast. We don’t want to be presumptuous as to exactly what that mix is. We just know or we have an expectation it will be meaningful. On the — I’m sorry, what was the second question again, Julien?

Julien Dumoulin-Smith: Yes. Just in response to Carly’s question, and you said something about sort of reengaging on the DRIP here, hundreds of millions of equity. When you think about that ratio of equity versus CapEx, are you thinking that you can keep the metrics relatively flat with that? Or are you kind of expecting that to use, if you will, some of the balance sheet capacity?

Dan Tucker: Yes. I would call it flat, Julian. So, it’s flat over the long term. Our credit quality is a buffer against adversity that we have no desire to consume nor do we have — or are we positioned where we’ve got to kind of over equitize incremental growth. It is a flat long-term objective.

Julien Dumoulin-Smith: Excellent. All right, guys. I’ll leave it there. Best of luck. I see you soon.

Operator: Our next question is coming from the line of Durgesh Chopra with Evercore ISI. Please go ahead.

Durgesh Evercore: Dan, just — I don’t want to jump the gun on ’24 here, but just wanted to sort of last year EEI, you were clearly sort of — you guys were articulating headwinds from rates and I think the ’24 numbers were subsequentially brought down. How do you think about sort of ’24 year again? Just qualitatively, obviously, there’s headwinds from rates that keep going higher, but then you’re showing a stronger load forecast prospectively. So, the puts and takes, how would you kind of articulate where ’24 is shaking right now versus your expectations at the beginning of the year?

Chris Womack: Let me start by saying I mean, I think we — as I said earlier, I mean, that is the things you’ve mentioned, that’s part of the process we’re in the middle of now that will lead us to February when we give you our ’24 guidance, but assessing the tailwinds that we are really excited about from economic development activities to the headwinds of interest rates. I mean that will all go into the calculus to the process of us kind of coming forth in February with our guidance for ’24. But I think it’s just a tab bit premature. And you’ve seen us in terms of how we do this. But we don’t give you any kind of indication or guidance at this point in time. We’ll do that in February of ’24.

Dan Tucker: Yes. And I guess it’s just a matter of discipline for us. This is you could go back to every third quarter transcript, script ever, and you’re going to hear the same answer. But I think it’s fair to say where we are. Chris and I are really excited about. Our value proposition I would stack up against anybody else’s right now.

Durgesh Evercore: Okay. I tried it at least.

Chris Womack: It was a good try.

Durgesh Evercore: Just maybe then just shifting back to discussion to the CapEx upside. How much — so obviously, billions of dollars, would you think of customer bill impacts. I guess where I’m going with this is there’s a pretty sizable load growth forecast that you were suggesting mid- to high single digits what percentage of that CapEx you think would go towards or the return would be satisfied by the slowed forecast versus increasing rates, if you could talk to that a bit.

Dan Tucker: Sure. Look, there’s a lot of moving parts here, as you can imagine. And I don’t want to get ahead of the regulatory process and things that will be evaluated in terms of the ultimate resource plan that’s decided on. But stepping back at a really high level, everything that we see from a load growth perspective relative to the resources needed to serve this growing peak load, and that’s key, right. You invest to make sure you can meet the peak loads, but the customers that you’re adding aren’t just using electricity at the peak, and it just so happens, the customers that we’re adding are expected to use electricity oftentimes 24/7. And so that kind of profile will provide more than sufficient revenue at the rate structures that exist today that is needed to pay for that capital. That is where the economic benefits for other customers have the opportunity to really help with this affordability equation.

Operator: Our next question is coming from the line of Andrew Weisel with Scotiabank. Please go ahead.

Andrew Weisel: Andrew, Okay. So first, it’s a quick one. Third quarter was obviously well ahead of the estimate. I know part of that is weather, but you’re still pulling to the midpoint of the full year range rather than something higher. Forgive me if I missed it, but what are the offsets relative to your outlook three months ago?

Dan Tucker: So, we didn’t really update the year-end three months ago. Again, just as that same discipline, we only address year-end on our third quarter call. And so it’s the first time we’re really refining it. It’s really about the first half of the year. Yes, we had a better-than-expected third quarter, but the headwinds of weather in the first half were pretty substantial. And that’s why we’re $0.34 below last year on a year-to-date basis. And so that’s the biggest driver of kind of the middle of guidance expectations at the end of the year. Now I say all that, Andrew, I mean, again, we put out quarterly estimates all the time, and I kind of challenge you to go back and find a time where we didn’t exceed that. So that should help with where our expectations are.

Andrew Weisel: Yes, definitely. Okay. Got it. So you’re back on track now, I guess, I could say. Next question is on Georgia, IRP. I know it’s off cycle. The typical cadence would have been to wait until 2025. How receptive are the regulators to this? I assume you’ve had conversations with the key intervenors. Is there any reluctance to breaking that three-year pattern? And as a follow-up, is there any thought to postponing some plant retirements? I know you talked about what you’re going to add and maybe sign contracts for existing assets, but any thoughts on postponing some of your retirements?

Chris Womack: Let me take a shot at a couple of things. And first of all, we never get ahead of our regulators. Secondly, I’d say as we were going through the ’22 IRP process, we did socialize and bring forth to the commission the activity that we saw occurring that there was a likelihood that there would need to be some update filing in between the three-year cycle. So this is not necessarily a surprise. We did mention that this would, in fact, be forthcoming. But yes, so we will go through the process, and hopefully, we’ll get a decision sometime by April of ’24 with this updated IRP. And what was the second part of your question?

Andrew Weisel: Potential to postpone plant retirements.

Chris Womack: As you look at this need that is there, that there is the likelihood that we would need some traditional units a little longer. Meaning, I think as we look at units that may have been scheduled to retire in ’28, we may look to take them into the 30s. So that is a possibility as we look to respond to this growing demand for our customers.

Dan Tucker: And while that’s an assumption in this IRP update, I think that will be a decision to be made in a future IRP proceeding in terms of those existing coal units.

Andrew Weisel: Okay. And just to clarify that you’re requesting a decision in April. Does that mean the CapEx update in February will not reflect anything related to this that will wait until February of 2025?

Dan Tucker: We’ll do our best to assess where we are. There may be some degree of uncertainty, but I think we’ll be able to reflect a good bit of it.

Chris Womack: Yes. And the scheduling order has not been established but we expect a similar process to the traditional integrated resource planning process. And so that would align with a decision sometime in the April time frame of ’24.

Operator: Our next question is coming from the line of Jeremy Tonet with JPMorgan. Please go ahead.

Jeremy Tonet: For those of us out of state, I was just hoping you could provide some in-state perspective with regards to Georgia and elections and the latest and what’s happening there with regards to litigation and potential for these elections. What are the next steps forward here? When could these materialize? Just any thoughts on that and any implications that could mean for Southern down the road?

Chris Womack: Yes. There’s a lot of activity around redistricting and lines from congressional seats. But in terms of the issue in Georgia regarding the Public Service Commission, the Rose case, that matter is still pending before the 11th Circuit quarter appeals. And there has not been a decision there. So the other matters that may go before the Georgia legislature you for redistricting. Those processes does not include matters consumed in the Rose case. So we are still waiting for a decision from the 11th Circuit on that matter.

Jeremy Tonet: Got it. I mean would you expect those two elections to be held in ’24 or just can’t really tell too much at this point.

Chris Womack: I think you answered your question. We can’t really tell us this time.

Jeremy Tonet: Fair enough. Fair enough. And then switching gears here, natural gas clearly a key component to the energy mix, as you talked about earlier. Just wondering, it’s not as easy to build a natural gas pipeline as it was at points in the past to supply into the state. I’m just wondering where nat gas that you see incremental supply coming from? Is this MVP? Is this other sources? Or just how do you see that dynamic at this point?

Chris Womack: A couple of things, I mean there are different lines and different processes that we’re in the middle of in terms of trying to expand pipeline capacity. And so we are working with existing companies; one, expanding on existing infrastructure where possible, but also working to find ways to, in fact, increase pipeline capacity and pipelines themselves all across our territory. So that’s all I can speak about that at this time. Yes, we know there are challenges there, but we think it is essential and important to support us being able to serve our customers with the reliability they demand and they need. And so, we are continuing to pursue various host of alternatives and options to make sure we have the supply that we need.

Jeremy Tonet: Got it. Fair enough. And one last one, if I could. Just be it related to Vogtle or otherwise, just wondering how could green hydrogen play into the IRP and your view? Any plans to test that out as a power plant fuel?

Chris Womack: And we have. I mean we’ve done one of the largest blends, and we’re looking at other opportunities. As you know, we participated in the hydrogen hub in the Midwest. We were not successful with the hydrogen hub that we participated in here in the Southeast, but we continue to have conversations and discussions with number of customers. And I think we’re all interested in finding ways to get the price of hydrogen down and thus also create the infrastructure to move hydrogen around. So yes, I mean, we’re still all arrows in the quiver, we’re looking at every option for renewable resources to meet the needs of our customers and hydrogen is a big consideration for us.

Operator: Our next question is coming from the line of Angie Storozynski with Seaport. Please go ahead.

Angie Storozynski: So just two things. One, a small one, Southern Power, I mean, I was kind of surprised to see the announcement about the solar project acquisitions. You have struggled to find any projects that actually makes sense from an economic perspective. Now we’re in a meaningfully high interest rate environment and now you’re going after these projects. So I’m just wondering if there’s something specific about these two projects? Or is it just that you are managing your FFO using some of the solar benefit and on the back of the IRA?

Dan Tucker: Yes. Great question, Angie, because it had been a while since we’ve done anything at Southern Power and really what changed was the IRA. So, we had stopped doing solar projects kind of middle of the last decade. We did a lot through 2015 through 2016 and then didn’t do any sense because we didn’t like the profile of investment tax credits for solar projects. The PTC is something that matches much better our regular, predictable, sustainable earnings profile and that the IRA kind of unlocked a lot of development activity on the solar front. And so the opportunity set was really big, and we narrowed it down to a couple of projects here recently that fit the kind of criteria we look for. Look, again, just to reiterate for everyone what we do at Southern Power, it’s long-term contracts, it’s creditworthy counterparties.

It’s returns that are better overall from an equity perspective than our regulated business, and it fits our overall profile. Southern Power is balance sheet financed, right? In of itself is a BBB+ company, and it’s an important. If you think about the bulk of Southern Power, the rest of it, the natural gas fleet you think about what’s happening with capacity needs in the Southeast, that business has become something of a crown jewel in the Southeast because it is one of the best providers of reliable, dispatchable capacity in the Southeast. So it’s a business that’s important to us, and these were two great opportunities to grow it.

Angie Storozynski: But again, it’s not again, when I think about Vogtle and the improvement in cash flow on the back of the COD of those units, you should be probably the very last or one of the very last utilities that needs to manage FFO using those PACS credits. So this is not…

Dan Tucker: This is not a credit play, Angie, that 0%.

Angie Storozynski: Okay. And then secondly, a different note. I saw that there was another management change of Alabama Power yesterday. Again, if I’m not mistaken, that’s the third one this year. Just caught my attention, if there is again, if it’s just the coincidence that we’ve had these three management changes at Alabama Power? Or is there something more to it?

Chris Womack: No, Angie, I wouldn’t read anything more than that. I mean you’ve had a number of individual leadership there who have put 40 years of service in that have chosen to retire, and then the opportunity to bring in and bring in some new talent. I think that helps the overall team. But as you know, we pay a lot of attention to succession planning. And we do a lot of work internally in terms of growing our teams. But I think we’re also wise enough to know when we can also go invest in some talent from the outside to bring in to our team and makes our overall team better. So I wouldn’t read anything more to it than just the reality of a couple of individuals deciding to retire and us moving some people around.

Dan Tucker: Yes. You didn’t hear that 40 years and then we’re back.

Operator: And our last question for today is coming from the line of Travis Miller with Morningstar. Please go ahead.

Travis Miller: Hello, you answered almost all my questions on the capital financing and even used where I was going to use creative, but I’ll throw out their nontraditional. Anything we’ve seen several other utilities who needed to raise financing, use some non-traditional mean divestitures, minority interest sale. Is that something in the toolbox for you? Or can we just rule that type of stuff out?

Dan Tucker: Yes. Look, there’s always a toolbox. I would argue our toolbox is a lot smaller than it used to be when it comes to alternative sources of capital. We did a lot of work over the last several years to kind of hone this portfolio of companies to something that really fits and that we feel really good about. So are there some small opportunities? Yes. But do we have any for sale sign sitting out there right now? No?

Travis Miller: Okay, makes sense and then a quick follow-up. The dividends, what do you think the Board is looking for to get off that $0.08 or lift growth rate to 4%, 5%, 6%? What are your thoughts around that?

Dan Tucker: Yes. I think it’s primarily just working our way down to a sustainable payout ratio, right? So if you think about where our guidance sits here in 2023, our payout is going to be something like 77% for 2023. That’s not a sustainable payout ratio for a growing company. Now that’s largely a function of the ROEs we’ve been earning at Georgia Power during construction of Vogtle 3 and 4. As that rolls off, that payout ratio will begin to come down, but we just need to get it somewhere comfortably into something that probably starts with a six in order to start evaluating a higher growth rate.

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

Chris Womack: Again, thank you, everyone, for joining us today. We really appreciate your interest in Southern Company. And we look forward to seeing many of you very, very soon. In the meantime, if you have questions, please give us a call. But again, thank you very much for joining us today.

Operator: Thank you, sir. Ladies and gentlemen, this concludes The Southern Company third quarter 2023 earnings call. You may now disconnect.