Title

Presentation

Duke Energy Corporation misses on earnings expectations. Reported EPS is $1.62 EPS, expectations were $1.7.

Operator: Hello, everyone, and welcome to the Duke Energy Third Quarter 2024 Earnings Call. My name is Felicia and I’ll be your operator today. Following today’s presentation, there will be a Q&A session. [Operator Instructions] I will now hand you over to your host today, Abby Motsinger, Vice President of Investor Relations at Duke Energy. Abby, please go ahead.

Abby Motsinger: Thank you, Felicia, and good morning, everyone. Welcome to Duke Energy’s third quarter 2024 earnings review and business update. Leading our call today is Lynn Good, Chair and CEO along with Harry Sideris, President, and Brian Savoy, CFO. Today’s discussion will include the use of non-GAAP financial measures and forward-looking information. Actual results may differ from forward-looking statements due to factors disclosed in today’s materials and in Duke Energy’s SEC filings. The appendix of today’s presentation includes supplemental information along with a reconciliation of non-GAAP financial measures. With that, let me turn the call over to Lynn.

Lynn Good: Abby, thank you, and good morning, everyone. Before I get into the third quarter results, I wanted to take a moment and recognize the extraordinary hurricane season that we’ve responded to this year. We’ve had three consecutive hurricanes: Debby, Helene, and Milton, each of which devastated parts of our communities. And my heart goes out to all of those who are directly impacted by these catastrophic storms, especially those who lost loved ones, homes, or businesses. Harry will provide further details on our restoration efforts in a moment and Brian will share cost estimates and plans for cost recovery later in the call. But I want to first commend our employees and utility partners, many of whom were personally affected by the devastation, for their remarkable response.

Our field teams rose to the challenge working around the clock to restore outages as safely and quickly as possible. And our customer care representatives, corporate responders, community relations managers and state President offices worked tirelessly to keep customers and policymakers informed. I’d also like to thank our state and local leaders, including Governor Cooper, Governor DeSantis and Governor McMaster and officials in our emergency operation centers for their partnership and coordination. I could not be more proud of our teammates and our partners for their unwavering commitment to our customers and communities. It’s important to note that our regulators and policymakers recognize the extraordinary efforts of our company in responding to these events and the feedback we have received has been overwhelmingly positive.

We recognize that our work is not done. It will take time for some of our communities to get back on their feet and we’ll be with them every step of the way. Turning to quarterly results on Slide 5. Today, we announced adjusted earnings per share of $1.62 for the third quarter compared to $1.94 last year. Brian will discuss the results in more detail, but I wanted to highlight a few things influencing this comparison. As you know, 2023 was impacted by historically weak weather early in the year and mitigation in the second half of the year. Significant mitigation efforts positively impacted third-quarter 2023 results. Third quarter of 2024 includes the full impact of Hurricane Debby and the mobilization of resources for Hurricane Helene. Helene and Milton will impact the fourth quarter.

And for both storms, we’re working with preliminary cost estimates which we will finalize by year-end. Hurricane costs are largely deferred or capitalized. However, there are a few exceptions and there’s no recovery mechanism for lost revenues. As a result and based on what we know today, we are reaffirming our 2024 guidance range, trending to the lower half. We are actively pursuing mitigation measures, some of which will naturally occur because of the resources devoted to the storms and others we will trigger through controlled spending through the balance of the year. And we will look for every opportunity without compromising on our commitment to safety and to our customers. As we look ahead to 2025 and beyond, we have strong momentum driven by our track record of constructive regulatory outcomes, including our recent IRP approvals in the Carolinas, as well as our robust growth in our attractive jurisdictions.

These tailwinds give us confidence in our long-term outlook and we are reaffirming our 5% to 7% EPS growth rate through 2028, up the midpoint of our 2024 range. And with that, I’ll hand the call over to Harry.

Harry Sideris: Thank you, Lynn. Let me begin on Slide 6, with our response to the historic storm season we faced over the last few months. The devastation in parts of our service territories, including my hometown of Asheville, North Carolina was unlike anything we’ve experienced before. Over the three hurricanes, we assembled more than 20,000 resources from across the U.S. and Canada and restored approximately 5.5 million outages in some of the harshest conditions. In August, Hurricane Debby entered our service territories near the Big Bend region of Florida as a Category 1 storm. The system then made its way north through our Carolina service territories, bringing high winds, heavy rain, and causing outages for 700,000 customers.

We were prepared and restored more than 90% of our customers within 24 hours. One month later, Helene, a Category 4 hurricane made landfall on September 26 and impacted every one of our service territories from Florida to Indiana. The storm brought record-breaking rainfall and flooding, created landslides and washed out roads and towns. In total, Helene led to approximately 3.5 million outages, with the hardest hit areas of Western North Carolina, upstate South Carolina, and the barrier Islands of Florida requiring significant infrastructure rebuild. Less than two weeks after Helene, Hurricane Milton, a Category 3 hurricane made landfall near Sarasota, Florida. The storm affected the majority of our customers in the state and led to over 1 million outages.

The St. Petersburg and Tampa Bay areas experienced the worst of the storm with rainfall of up to 16 inches and extensive wind damage. We restored nearly 600,000 customers in 48 hours and 95% of all customers within four days. Our success in responding to storms of this magnitude is due to our strategic preparation ahead of the storms near constant communication with customers and stakeholders, and most importantly, the tireless work of our employees and utility partners. Each of our 27,000 Duke Energy employees has a storm role and the response effort is truly all hands on deck. I want to specifically recognize those on the front lines, our crews who work night and day to restore power, no matter how hard. For example, two Duke Energy line workers hiked through miles of difficult terrain to restore power to the Ashville Veterans Hospital following Helene.

And this is just one heroic example of hundreds throughout our response. Our team’s dedication and commitment, along with close coordination with local, state, and federal agencies allowed us to make progress faster than we expected. Another key to our successful response was the grid-hardening investments we’ve deployed across the system. Last year alone, we invested more than $4 billion to harden and modernize the grid. This included targeted undergrounding, pole upgrades to steel and concrete in coastal areas, and self-healing technology. These investments helped avoid nearly 550,000 customer outages in saving 7 million hours of total outage time across all three storms. Going forward, we’ll continue to invest in these critical infrastructure assets with grid investments accounting for half of our five-year $73 billion capital plan.

Turning to Slide 7, I’ll share progress on our near and long-term strategic priorities. In the Carolinas, we are pleased to receive constructive approvals on our Carolinas resource plan earlier this month. The North Carolina Utilities Commission issued an order November 1st, accepting our settlement with public staff and other parties in its entirety. And on Monday, the Public Service Commission of South Carolina issued a directive approving our IRP and recommended portfolio. We expect an order by November 26th. These timely commission approvals allow us to advance our near-term investments while maintaining our share commitment to preserving reliability and affordability as we meet our state’s growing demand for power. In Indiana, last week, we filed an updated IRP after an extensive stakeholder engagement process.

Our preferred scenario is designed to balance reliability of service and customer affordability. Plans for natural gas assets, renewables, and battery storage also add diversity to our generation resources in the state. As in all jurisdictions, there will be a robust review of all planned resource additions. We expect to file a certificate of public convenience and necessity for new and expanded gas generation at Cayuga station in early 2025. Shifting to Florida, in August, the commission approved our settlement agreement with unanimous support. The three-year multi-year rate plan allows for timely recovery of grid, solar, and battery investments. New rates will be effective in January. We also reached a comprehensive settlement in our Piedmont Natural Gas North Carolina rate case in September, resolving all matters in the proceeding.

Investments will focus on federal safety regulations, enhancing the customer experience, and providing safe, reliable natural gas service. We expect an order in January of 2025. With these outcomes, we’ve settled or received approval for approximately $80 billion of rate-based investments across eight rate cases since the start of 2023. We have multi-year rate plans in place in our largest jurisdictions through the end of 2026, which smooth rate impacts to customers and provide line of sight to growth. These outcomes support essential critical infrastructure investments, acknowledge the rising cost of capital through higher ROEs, and allow us to meet our customers’ demands for affordable, reliable, and increasingly clean energy now and into the future.

With that, let me turn the call over to Brian.

Brian Savoy: Thanks, Harry, and good morning, everyone. As shown on Slide 8, our third quarter reported and adjusted earnings per share were $1.60 and $1.62, respectively. This compares to reported and adjusted earnings per share of $1.59 and $1.94 last year. Within the segments, Electric Utilities and Infrastructure was down $0.09. O&M was higher in the quarter, largely due to unplanned hurricane restoration costs from Debby and Helene. Results were also impacted by lost revenue from storm-related outages and evacuations. As expected, growth from rate increases and riders were partially offset by higher depreciation and interest expense. Moving to Gas Utilities and Infrastructure. Results were down $0.04 compared to last year, mainly due to higher interest expense and depreciation on a growing asset base.

And finally, the other segment was down $0.19, primarily due to planned to a planned higher effective tax rate, which reflects tax efficiency efforts realized in 2023. Our 2024 effective tax rate is tracking in line with our full-year guidance of 12% to 14%. Turning to storms, our preliminary total cost estimate for the three hurricanes is between $2.4 billion to $2.9 billion for the year, and we recognized approximately $750 million in the third quarter. Most of these costs will either be deferred for future recovery or relate to capital projects to rebuild portions of the system. We are advancing cost recovery strategies through established mechanisms and have a long track record of constructive outcomes. We’re targeting rider recovery in Florida beginning in early 2025 and receipt of securitization proceeds in the Carolinas by the end of next year.

Looking ahead to the remainder of 2024, we expect fourth-quarter adjusted EPS to be higher than last year due to growth from rate increases in the electric and gas segments and higher sales volumes. And as Lynn mentioned, we have cost agility initiatives underway to reduce spending, which will drive O&M lower in the fourth quarter compared to last year. We’ve outlined our fourth-quarter drivers in the appendix of the presentation. With these drivers in mind, we are reaffirming our 2024 guidance range of $585 million to $610 million. Based on what we know today, we are trending to the lower half of the range, primarily due to storm impacts, including restoration costs and lost revenues from record customer outages. Moving to Slide 9. Third quarter weather normal volumes increased 1.1% versus last year, driven by strong commercial volumes and residential customer growth.

In the Carolinas, We’ve added approximately 75,000 residential customers year to date, roughly 10,000 more than the same period last year. And in Florida, We’ve added nearly 30,000 residential customers, also outpacing last year. We continue to see robust economic development activity and in the past month have signed letter agreements for 2 gigawatts of data centers. These agreements are emblematic of conversations we are having with large customers all around our service territories and represent continued advancement of projects in our pipeline. As a result, we’ve increased the high end of our 2028 economic development forecast to up to 20,000 gigawatt hours of incremental load. This represents a 2,000 gigawatt hours increase since our second quarter update.

As a reminder, we take a risk-adjusted approach as we evaluate which economic development opportunities to include in our forecast. In the near term, we continue to see a slower rebound in certain industrial sectors. We are in frequent dialogue with our largest customers and they continue to signal expectations for a recovery, but the timing has shifted into 2025. Additionally, as with any extreme weather period, third-quarter weather normal volumes likely reflect some impact from the major storms. Overall, we’re seeing steady improvement in our rolling 12-month volumes and are trending toward our 2024 load growth target of 2%. And over the long term, we see load growth at the top end of our 1.5% to 2% CAGR through 2028, with annual load growth accelerating in 2027 and 2028 as large economic development projects come online.

Turning to Slide 10. We have provided key growth drivers for 2025. We’ve executed an active regulatory calendar over the past two years that has yielded constructive outcomes and positioned us well as we head into next year. Beginning with the Electric segment, in Florida, we’ll implement the new multi-year rate plan with an updated 10.3% ROE in January. In the Carolinas, we’ll implement the second year of the North Carolina multi-year rate plans and see a full-year impact from the DEC South Carolina rate case. And in the Midwest, we expect the Indiana rate case to be effective in March. Finally, we’ll see retail sales growth from economic development and population migration in addition to increases in rider revenues. In the Gas segment, we’ll see growth from the Piedmont North Carolina rate case, integrity management investments and customer additions.

We will provide 2025 earnings guidance in February along with updated load growth expectations and our refreshed capital and financing plans. As we signaled, we expect our capital plan to increase as we move further into the energy transition. We also expect capital to increase in the near term as a result of a higher pace of customer additions and refresh cost estimates for generation investments that ramp up in the remainder of the decade. We are well positioned for the opportunities presented by this unprecedented demand growth and we will take a balanced approach to funding the incremental capital, supporting our growth rate and balance sheet strength. Moving to Slide 11. We’ve made significant progress on credit-supportive initiatives.

The constructive regulatory outcomes we’ve achieved with increasing ROEs and timely recovery of investments have driven considerable improvement in our operating cash flow. And in October, we efficiently monetized nearly $200 million of energy tax credits that will benefit customers over time. We expect additional transactions in the fourth quarter. We’ve collected over $3 billion of deferred fuel since 2023 and are on track to be at our normal level by year-end. We’ve also completed over 80% of our planned $500 million equity issuances through the DRIP and ATM programs, having priced $400 million year-to-date. As I mentioned earlier, we will pursue storm cost recovery through established mechanisms in our states, including securitization in the Carolinas and our storm rider in Florida.

We expect a temporary credit impact in 2024 and are targeting 14% FFO to debt in 2025, 100 basis points above our Moody’s downgrade threshold. In reports issued in October, both Moody’s and S&P concurred that the impacts from the storm will not have a long — any long-term credit implications. As we demonstrated over many years, our commitment to our current credit ratings and our strong balance sheet will continue to be a top priority as we execute our growth objectives. Turning to Slide 12. We operate in constructive growing jurisdictions and the fundamentals of our business remain strong. Our track record of regulatory execution has us well-positioned to achieve our long-term 5% to 7% growth target through 2028, which combined with our attractive dividend yield, provide a compelling risk-adjusted return for shareholders.

With that, we will open the line for your questions.

Operator: [Operator Instructions] The first question comes from Shar Pourreza from Guggenheim Partners. Please go ahead. Your line is now open.

Shar Pourreza: Hi, guys, good morning.

Lynn Good: Good morning, Shar.

Harry Sideris: Good morning.

Brian Savoy: Good morning.

Shar Pourreza: Morning, morning. Just on — let me just start on overall credit. Post storms, you guys are still I guess above your downgrade threshold for ’25. Where are you right now and what is the FFO impact from the storms? And then on the tax credit monetization side, it’s obviously a key source of FFO for you. You guys have guided to a monetization figure this year around $300 million to $500 million. I think you recognized about $200 million. Do you expect to hit the range and where within the range is the market kind of slower to develop? So just an overall credit question would be great. Thanks.

Lynn Good: Sure. Brian, why don’t you take that?

Brian Savoy: Certainly. Good morning, Shar. So on the credit, I mentioned that the storm costs are going to temporarily impact our credit in 2024. And as we recover these costs through established mechanisms in ’25 that will be resolved. And as we think about where we’re tracking on 2024, I would view us in the high 13s is where we plan on landing and that has some of the financing impacts from $2.5 billion of storm costs that we expect that we incurred in 2024. On the tax credit monetization, we completed $200 million so far and we have contracts in place that we plan on closing in the next month to get to the top half of that range that we signaled earlier this year. So I’d say we’re tracking right in line with our expectations.

And really all the credit-positive initiatives that we had underway, rate cases going to into effect, fuel recovery, monetizing tax credits, all those are tracking at or above our targets for the year. So we feel really good about where we stand on credit and that’s why we have a lot of confidence in our 2025 credit outlook.

Lynn Good: And Shar, the only thing I would add…

Shar Pourreza: Got it, Brian. But just – yes.

Lynn Good: Yes, I was just going to say we’ve also been in conversation – yes, as you would expect, we’ve been in conversation with the agencies and they are completely comfortable with the plan. We had demonstrated success, as you know, in collecting storm costs in both Florida and the Carolinas. So as Brian said, we are on track with every element and we’ll execute as you would expect us to.

Shar Pourreza: Got it. Just, Brian, if the storms didn’t happen, where would your metrics be versus the high 13% range you are now?

Brian Savoy: Yes, if storms didn’t happen, we’d be at 14%, 14%-plus.

Shar Pourreza: Okay, thanks. And then, I know, obviously, we’re heading into the typical bigger update on the year-end call, but just I want to get a sense on sort of the load environment. I mean, you guys are still running the 1.5% to 2% figure, which doesn’t really jive with what’s been going on around the country. So, a lot of your peers have jumped ahead and revised their load growth figures. They’re quantifying the impacts and it’s actually hitting their numbers. You did slightly, as you highlighted, uptick the economic development figures. I guess maybe just a little bit of it from a trend perspective, what we should expect from Duke? Are you seeing similar trends as what we’re seeing around the jurisdictions and do you expect it to potentially be accretive to your numbers? Thanks.

Brian Savoy: No, Shar, I think it’s a great question. And one, we’ve kept our CAGR of 1.5% to 2% long-term on load growth and signaling we’re trending to the top end of that range and we’ll update it in February. And we are trending at the top and we expect that range to move as we look to next year, Shar. Because the economic development opportunities are not slowing down and they’re very sizable. We mentioned the 2 gigawatts signed in this quarter, that’s just an example of many conversations that are going on that shore up our pipeline and expand it. And so you should expect the load growth to go up as we roll the plan forward. And we will bring that up in February with the Folsom update.

Lynn Good: And Shar, I think it’s important to…

Shar Pourreza: Okay. Sorry…

Lynn Good: We talked — yes, we talked CAGR, right? So compound annual growth rate, but as you look at ’27 and ’28 as depicted on the chart, we are seeing acceleration. And so we’ll continue to provide visibility on this. And of course, watch these every step of the way. They also included discounts in them because we’re trying to be conservative recognizing that some of these projects can tend to shift to the right. So we’re introducing a bit of that as well, and we’ll continue to update. So sorry, did you have another…

Shar Pourreza: Got it. So — no, no, Lynn, there was just a follow-up on what you just said is. So there is some accretive opportunities, I guess, above your current range potentially. Is that kind of the message?

Lynn Good: I think that’s right, Shar. And if you look at the chart, you can see it kind of sitting in ’27, ’28.

Brian Savoy: Yes. I would just add, the projects that we’re talking to customers about today will show up in late ’27, ’28 and ramp up in the balance of the decade. So you’re going to see this kind of burst of activity that will be signing contracts that will come to reality in ’27, ’28, ’29, when we see acceleration of load growth.

Shar Pourreza: Okay, perfect. Thank you guys so much. See you in a couple of days.

Brian Savoy: Thank you, Shar.

Lynn Good: Thank you.

Operator: The next question comes from Julien Dumoulin-Smith from Jefferies. Please go ahead.

James Ward: Hi, guys. You’ve got James Ward here, instead of Julien.

Lynn Good: Hi, Julien.

James Ward: How are you?

Lynn Good: Good.

James Ward: Hi, you got James here. Hi, Harry. Hi, we’re looking forward to seeing you this weekend.

Brian Savoy: Yes.

James Ward: A quick question on FFO to debt. Obviously, when the first hurricane hit, you talked about 10 basis points of impact. Got the negatives there that I think either people will ask about or you’ve kind of been addressing. I’d like to talk about the tax credit monetizations instead. You monetized $200 million last month in October. You mentioned expecting to monetize more by the end of 2024. How should we think about that potential monetization in terms of the size, the discount that you’re seeing, and just for comparability purposes? And how impactful do you think it could be by year-end to FFO to debt? And then as a follow-on, just sort of into next year and that’s my question. Thank you.

Brian Savoy: That’s very good, Julien. This is Brian. I’ll take that. So what we’re seeing in the tax credit market, it’s deepening. And the discounts that we’re being able to realize on our tax credits are very attractive. So think about mid-90s or even slightly above. So I think there’s a lot of taxpayers that are looking to reduce their tax bill and they’re lining up to get high-quality credits from good credit quality sellers, right? So the — we did $200 million in the past month and we’ve geared up our process to close the rest this year and the size that we were targeting coming into the year, Julien, was around $300 million to $500 million. We’re trending to the upper part of that range, right? And the market has been growing and deepening, and we’ve not seen any hesitation by buyers.

And what that equates to is about 40 basis points to 60 basis points in the FFO to debt, right? And a big chunk of that is nuclear tax credits and there’s also some solar PTCs inside of that figure. And as we look to next year, we’ll have more of both, right, more nuclear, more solar. And so you see it being accretive to the FFO for a few years to come.

James Ward: Got you. Then as just a quick follow-up there, should we be assuming for the 40 to 60, I get to the solar in there as well? But for the nuclear PTCs, should we treat them as all being monetized? So whatever the assumption is that we’re modeling in for next year and so I get that in 2030 as well. Obviously, you get the reversal and you’re not getting that benefit anymore, just the way the math works as you amortize them back to customers. But for the next few years, should it be one-for-one? You get them, monetize them. Is that the right way to think about it? Plus solar or is there another nuance?

Brian Savoy: No, that’s the right way to think about it, Julien, yes.

Lynn Good: Hi, Julien, you may recall, we have set forth a pretty creative method of retaining these credits for a period of time and then amortizing them to customers over a four-year period. And so that amortization is very modest in ’25 and ’26. And then we’ll get on a path of amortizing about 25% of them as generated in ’28 and forward. So all of that is contemplated in our five-year plan and credit. And it’s one of those incredible opportunities that not only strengthens credit, but lowers price of our product to customers in a way that I think is really helpful to our growth plans.

James Ward: Absolutely. Definitely makes sense. And a final point on the amortization. Could you remind us if that — it’s ingrained via the second settlement for sure for DEC, but just for South Carolina and then for DEP, kind of where does that stand in terms of being formalized? I think we’re all using that four-year assumption from the initial case and second settlement, but is that — has that been further made concrete, I guess?

Lynn Good: Yes. And let us provide you with an update on that. But North Carolina is memorialized. In South Carolina, we’re deferring the credits for consideration in the future. I think the North Carolina method though is a good planning assumption for the Carolinas and we can get you more details on those specifics, Julien, if that would be helpful.

James Ward: Yes, offline. Thank you. Thanks so much. Thank you very much. Really appreciate the color.

Brian Savoy: Thank you.

Operator: The next question comes from Nick Campanella from Barclays. Please go ahead.

Nick Campanella: Hi, good morning. Thanks for taking my questions.

Brian Savoy: Good morning, Nick.

Lynn Good: Good morning.

Nick Campanella: It’s great to see — good morning. It’s great to see Moody’s supportive here and I know that there’s been really constructive effort on the ground with local constituents as well and dealing with the storm. I guess, you did preview in your prepared remarks, there’s going to be higher capital coming in the near term, Brian. And just wondering how you’re thinking about the need to pull forward any equity, if at all. You do seem confident on the year-over-year into ’25 as well, but just wanted to check on that. Thanks.

Brian Savoy: Nick, we have $500 million of equity in our capital plan and our financing plan today per year in the five-year plan. And in February, we’ll come up with our new capital plan, which I’ve signaled will be higher. And there’ll be some in the near term and some because 2029 is going to be much larger than 2024. We’ll have our full financing plan at that point and provide how we’re going to fund that plan then. Right now, I would not signal any additional equity.

Lynn Good: What I would suggest, Nick, on…

Nick Campanella: That’s great.

Lynn Good: On the equity is we — yes, as we expand capital, we will finance it in a balanced way. I think we’ve given a range of 30% to 50% of equity related to new and incremental capital. So I think that’s a planning assumption that would be appropriate.

Nick Campanella: That’s great. And then something that’s come up on earnings call a bit more this season is just new nuclear. And I know that you’ve had some exploratory frameworks, whether it’s for SMR or otherwise announced a few quarters ago. Could you just maybe talk about how you see Duke participating in new nuclear, whether it’s kind of large-scale or small-scale into the end of the decade? That’d be helpful. Thanks.

Harry Sideris: Yes, Nick, this is Harry. I’ll take that question. We see a lot of promise in SMRs. Our customers and stakeholders are very supportive of it. Our states appreciate the economic development that it provides for the communities that we serve. And recently, some of our large tech companies are showing great interest in new nuclear. At the same time, it’s a decision we continue to closely evaluate to make sure that it’s in the best interest of our customers and our investors as we move forward. In our current IRP plans that just got approved, both North Carolina and South Carolina approved the early development activities and we will continue to follow their lead as we move forward. But any decision as we move forward, we’ll have to address three key items.

The first one is the first of the kind risk that exists, really around the maturity of the technology, the supply chain. The second item is cost overrun protection to protect our investors and our customers. And then our third is to make sure that we can protect our balance sheet for making these investments. So we’ll continue to work with our commissions as we look forward to making a decision there.

Nick Campanella: Hi, I appreciate it, and I’ll see you guys soon. Thank you.

Lynn Good: Thank you, Nick.

Harry Sideris: Thank you.

Operator: Next question we have comes from Durgesh Chopra from Evercore ISI. Please go ahead.

Durgesh Chopra: Hi, good morning, team. Thanks for giving me time. Just, hey, Brian.

Lynn Good: Good morning.

Durgesh Chopra: Hi, good morning, Lynn. Brian, can I just ask you to clarify, what is the earnings impact, the combination of restoration costs and lost revenues from the three hurricanes? What does that impact in 2024?

Brian Savoy: Yes, Durgesh, you could think about it. We plan for storms in a year, but we don’t plan for the historic storm season we just experienced in the past two months. And the restoration costs that would lead to the O&M and the P&L, a few cents of that as well as a few cents of lost revenues because we had 5.5 million customers out for multiple days. So that’s how I think about it, few cents each on the O&M for the storm costs that were kind of out of bounds with what our normal level would be and the lost revenues.

Lynn Good: And, Durgesh, I would point to, if you look at the drivers for the third quarter, you see us with O&M greater than third quarter of ’23. That’s largely impacted by storm expense. And then, if we look at the fourth quarter, the majority of — a large amount of restoration for Helene sits in the fourth quarter as well as Milton, all of Milton. And so the revenue — expected revenue impact from outage will impact the fourth quarter as well. So when we look at it in total, it’s both of these things that are really driving us to be below target in the range. But you should know, as you’ve seen us do many times, we will do everything we can to mitigate this. And that’s the posture that we’re assuming here for the fourth quarter and have a high degree of confidence that we will constrain the hurricane impact to 2024. And so our optimism around 2025 and the growth that this company offers to investors remains unchanged.

Durgesh Chopra: That’s very helpful. Thank you. And maybe just talking to that growth, Lynn, I mean, I think in the Q2 call and obviously, earlier today you reaffirmed the 5% to 7% on the Q2 call. I just want to be clear. You talked about perhaps getting to the higher end of that 5% to 7% EPS growth at the back end of the plan. Is that still sort of the way you are projecting that growth to trend?

Lynn Good: Durgesh, it’s really — that is a good question and it is really consistent with the conversation we just had with Shar around load growth. So when you look at ’27 and ’28 and that chart that sort of has a bit of a slope to it and you see us deeper into the energy transition with increasing capital, that’s what we’re pointing to is the potential we have to get higher in the range. So we’re working hard in that direction and believe we’ve got the potential and the constructive regulatory outcomes that we’ve been delivering time and time again really underpin our confidence.

Durgesh Chopra: Okay. Thank you again for taking my questions.

Operator: Next question comes from Anthony Crowdell from Mizuho. Please go ahead.

Anthony Crowdell: Hi, good morning, Lynn, good morning, Brian, and good morning, Harry. I want to leave you out. Apologies. I guess just quickly, just after Durgesh’s question which I think followed up on Shar’s question and he talked about maybe at the end of the decade, maybe leaning towards the higher end of the EPS CAGR. Any thoughts with the load growth and also when you look at these historic storms or maybe widening the credit cushion that you guys have and maybe using the load growth and the enhanced earnings growth of making a wider cushion beyond the 150 basis points you’re working on now?

Lynn Good: Anthony, it’s a good question and something we spend a lot of time thinking about and we’ll be working in that direction and thinking also planning for some more contingency around storms and our annual planning will also be a part of that. So as you would expect us to do, we’ve learned from every one of these events and 2024 will be no exception.

Anthony Crowdell: And just have one follow-up. And I don’t know if you’ve quantified it. Just you’re talking about additional maybe mitigation measures for the fourth quarter, has the company quantified what they expect from a normal run rate to a pull out of fourth quarter?

Lynn Good: We haven’t quantified something specifically, Anthony, and I want you to know that there’s a ton of work going on, but we’re only about two weeks past Hurricane Milton. So we’re working. And when we talk about our range and the expectation we’ve set for the full year, that implies that we are going to keep going. And we actually believe that the quantification of the mitigation could put us in a position where O&M is lower than ’23. But I don’t want to get any more specific than that given where we are in the process.

Anthony Crowdell: Great. Thanks for taking my questions, and I’ll see you guys in Hollywood.

Brian Savoy: Thank you.

Lynn Good: Thank you.

Brian Savoy: See you, Anthony.

Operator: The next question comes from Jeremy Tonet from JPMorgan. Please go-ahead.

Unidentified Analyst: Hi, good morning. This is actually [Aiden Kelly] on for Jeremy. Just wanted to dive into the — hey, how’s it going? Just wanted to dive into the 2 gigawatts of incremental data center growth a bit further. Was this comprised of several large single or multiple customers? And then could you confirm whether Microsoft’s land acquisition in North Carolina is embedded in this forecast or maybe incremental here?

Brian Savoy: Ian, it’s a good question. The 2 gigawatts right now, this work is confidential, so we’re not going to share the customer information. But I will say when we sign letter agreements. What that means is the customer has a site identified and land secured either through options or purchased. And what happens next is that we will negotiate with that customer over the next eight to 10, 12 months on the Energy Service Agreement. And that codifies what the contract will be between us serving that customer and what that customer will pay for its energy. And so you’d expect all these details to come out over the next year. And I mentioned in my prepared remarks, this is emblematic of what we’re seeing across the board. We’re talking to many customers in this arena and I’m not going to talk specifically about Microsoft’s acquisition of land, that was in an article recently.

But we’re having talks with many customers and they’re very serious about citing their data centers in the Carolinas specifically because in the Carolinas over half our energy is carbon-free nuclear. And that’s very attractive to the data centers. So we see this as a great opportunity for us and we’re seeing it come to reality as we sign agreements like these.

Unidentified Analyst: Got it. That’s helpful. Thanks. And then maybe just any thoughts on how election results could impact your resource mix and generation portfolio? Maybe specifically regarding coal plant retirements or renewables additions? And then could you talk about any industries that could be impacted in your territory by maybe manufacturing, restoring and give any incremental load growth in your forecast from this?

Lynn Good: I’ll take that one, Ian. We’re digesting election results and looking at both federal and state, I think congratulating — I want to extend congratulations to President Trump on his work and really look forward to working with his administration on our task of delivering affordable, reliable power. I think the U.S. economy will be a focus and a priority of his and our industry plays an incredibly important role. So as we look at what we’re doing here in the Carolinas and also Indiana and Florida, we are putting infrastructure in place in order to serve economic development and believe there are lots of opportunities to work together. And similarly, with our states, we had two gubernatorial elections, one in Indiana, one in North Carolina.

The governors in both states are people we know well who understand the important role that the utility plays in investing in infrastructure and driving growth. And so we’re anxious to work with those administrations as well. And, I think our conviction around delivering affordable and reliable energy is something that will resonate in our states and also at the federal level.

Unidentified Analyst: Appreciate the color there. And then just maybe one more, if I could add it in, could you just quantify roughly per year how much in transferability you’re seeing?

Brian Savoy: On the energy tax credits, Ian?

Unidentified Analyst: Yes, correct.

Brian Savoy: We signaled 40 basis points to 60 basis points of FFO to debt improvement from these tax credit sales in 2024, and that equates to about $300 million to $500 million of monetized tax credits in a year. And so you could think about it in that kind of range for the next several years.

Unidentified Analyst: Got it. Appreciate all the color there. I’ll leave it there. Thanks.

Lynn Good: Thank you.

Brian Savoy: Thank you.

Operator: Thank you. The next question comes from Carly Davenport from Goldman Sachs. Please go ahead. Your line is now open.

John Miller: Hi, good morning, guys. This is actually John Miller on for Carly. Thanks for taking my question. Maybe to start on the Indiana IRP, can you maybe talk about what’s new in that updated filing and then kind of what the total opportunity there looks like now?

Harry Sideris: Yes, I’ll take that one, John. We filed our IRP last week in Indiana. We’ve been working with stakeholders for many months on that plan. It really is transitioning our Cayuga plant to gas, adding storage and solar, really diversifying the fuel supply we have in Indiana and also working through our Gibson facility and what we’re going to do there in the future. So very broad stakeholder support for our plans. We will be filing the CPCN at the Cayuga plant at the beginning of next year and expect to be moving forward with the plan in the IRP as we progress into next year.

John Miller: Got it. That’s helpful. And then maybe on the Carolinas IRP with the North Carolina order deferring some natural gas to next year for the next resource plan. I guess, one, when in 2025, do you expect to file that resource plan and then how should we think about the size of it? Will it be a smaller filing or could it be similar in size to the outstanding resource plan?

Harry Sideris: So we’re very pleased that we got the IRPs approved earlier last week and this week, both in North Carolina and South Carolina, very constructive orders. It really allows us to move forward with our near-term actions that we have in both states. We will be filing updates to those plans next year, but don’t anticipate a tremendous difference in what we’re planning. We’re really focused on those near-term actions in advancing the items that we’ve put in place there, very constructive work with stakeholders as we move forward. We have our CPCNs for some of the gas generations that we expect to hear back from by the end of the year as well to proceed with those constructions projects at Person County.

John Miller: Got it. That’s helpful. Thanks.

Harry Sideris: Yes.

Operator: We have no further questions, so I will hand back the call to Lynn Good for closing remarks.

Lynn Good: Great. Well, thank you all, and we’ll see you in a couple of days. Looking forward to the EEI Financial Conference. I want to thank you for your questions and for your investment in Duke Energy. Talk soon. Thank you.

Operator: Thank you, everyone. This concludes today’s call. You may now disconnect your lines.