Duke Energy Corporation (NYSE:DUK) Q4 2022 Earnings Call Transcript

Duke Energy Corporation (NYSE:DUK) Q4 2022 Earnings Call Transcript February 9, 2023

Operator: Good morning. Thank you for attending today’s Duke Energy Fourth Quarter and Year-end 2022 Earnings Call. . I would now like to pass the conference over to your host, Abby Motsinger, Vice President of Investor Relations. Thank you. You may proceed.

Abby Motsinger: Thank you, Joel, and good morning, everyone. Welcome to Duke Energy’s Fourth Quarter 2022 Earnings Review and Business Update. Leading our call today is Lynn Good, Chair, President and CEO, along with Brian Savoy, Executive Vice President and CFO. Today’s discussion will include the use of non-GAAP financial measures and forward-looking information within the meaning of securities laws. Actual results may be different than forward-looking statements, and those factors are outlined herein and disclosed in Duke Energy’s SEC filings. The appendix of today’s presentation includes supplemental information and disclosures, along with the reconciliation of non-GAAP financial measures. So with that, I’ll turn the call over to Lynn.

Lynn Good: Abby. Thank you, and good morning, everyone. Today, we announced adjusted earnings per share of $5.27, closing out a successful 2022. We achieved results solidly within our updated guidance range while making significant progress on our strategic goals, responding to external pressures and delivering constructive outcomes across our jurisdictions. As a result, today, we’re reaffirming our 2023 guidance range of $5.55 to $5.75 with a midpoint of $5.65. We’re also reaffirming our 5% to 7% growth rate through 2027 off the midpoint of our 2023 range. This reflects the strength of our regulated businesses, our disciplined approach to cost management and a robust $65 billion capital plan that supports our thriving jurisdictions.

Before I turn to our regulated utilities, let me provide a brief update on the sale of our Commercial Renewables business. The sales process continues to progress. But as with the sale of any large-scale business, the timing tends to evolve. We remain on track to exit both the utility scale and the distributed energy businesses and now anticipate proceeds in the second half of the year. We will continue to keep you updated along the way. Turning to Slide 5. We’ve reached a significant milestone in our clean energy transition. On December 30, the North Carolina Utilities Commission issued an order adopting an initial carbon plan. This constructive order is the culmination of years of work with policymakers and stakeholders to chart a responsible path for the energy transition.

The order recognizes the value of an all-of-the-above approach to achieving carbon reduction targets in a manner that balances affordability and reliability for customers. The near-term action plan provides approval of 3,100 megawatts of solar and 1,600 megawatts of storage as well as transmission upgrades to support the integration of these renewable resources. The commission also approved limited development activities associated with longer lead time investments, including small modular nuclear reactors, pumped hydro and transmission related to offshore wind. And as part of an orderly transition out of coal by 2035, the commission supported planning for approximately 2,000 megawatts of new natural gas generation to maintain reliability. Through its order, the commission reinforced the importance of maintaining a diverse generation mix while conducting an orderly clean energy transition and was clear that ensuring replacement generation is available and online prior to the retirement of existing coal units is a shared priority.

The carbon plant provides a constructive road map that delivers on our strategic priorities and supports the needs of our customers and communities today and into the future. It supports our capital plan and provides the clarity we need to advance critical near-term investments. We look forward to continuing our progress through our updated carbon plant filing in North Carolina later this year. Moving to Slide 6. We’re making meaningful progress on our strategic initiatives in each of our jurisdictions. In North Carolina, we filed our first performance-based rate application for our Duke Energy Carolinas utility on January 19, which followed a similar filing for our DEP utility last fall. The request includes a multiyear rate plan to fund system improvements to meet the growing needs of our customer base, including $4.7 billion of capital projects that are expected to go into service over the 3-year period.

These investments are primarily T&D-related projects that support the security and reliability of the grid as well as approximately $300 million of solar and storage investments consistent with the carbon plan order. Our request is mitigated by a reduction in operating costs since our last rate case, evidence of our continued ability to manage costs to keep customer rate increases down. Evidentiary hearings are expected to begin in the third quarter and consistent with past practice, we intend to implement temporary rates in September, subject to refund. If approved, we expect year 1 revised rates to be effective by early 2024. In South Carolina, we were very pleased to reach a comprehensive settlement in January with all parties in our Duke Energy Progress rate case.

The settlement, which is subject to commission review and approval includes a 9.6% ROE, the continuation of deferrals for grid and coal ash spend and supports accelerated retirement dates for certain coal units. In fact, the settlement is on the commission’s agenda for this afternoon. And if approved, new rates are expected to be implemented in April. We also plan to file an updated IRP in South Carolina later this year, which will take into account the carbon plan and the Inflation Reduction Act. Turning to Florida. On January 23, we filed a petition to adjust customer rates for deferred 2022 fuel costs, less the impact of lower forecasted fuel prices in 2023. We are also flowing back IRA tax savings to our Florida customers as of January 1.

In Indiana, we’re updating our IRP to reflect results of the 2022 RFP process, regional transmission operator requirements and the Inflation Reduction Act. We expect to begin filing for certificates of need for new power generation in the second quarter. In Ohio, the commission approved in full our electric rate case settlement in December, which supports the recovery of grid investments to improve reliability and service for our customers. In December, we also filed an electric rate case in Kentucky. The request reflects more than $300 million in investments we’ve made to strengthen the generation and delivery systems as well as updated retirement dates for our Kentucky fleet. As we advance our regulatory strategy, affordability remains top of mind.

Brian will go into more detail on steps we’re taking across our jurisdictions to lower costs for customers. Finally, I want to highlight a well-deserved recognition for our Piedmont Natural Gas team. In December, J.D. Power ranked Piedmont #1 in residential customer satisfaction for natural gas service in the Southeast. This is the first time Piedmont has received the #1 ranking and is a testament to the commitment to our customers. In summary, 2022 was an extraordinary year for Duke Energy as we made strong progress executing our strategy, responding to difficult external pressures and advancing our clean energy transformation. Our path forward remains clear. As we continue to navigate our energy transition, we will do so responsibly, preserving affordability and reliability for our customers and remaining good students — stewards of communities.

I’m confident that our strategy will continue to deliver consistent and lasting benefits to our customers, communities and investors. With that, let me turn the call over to Brian.

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Brian Savoy: Thanks, Lynn, and good morning, everyone. Turning to Slide 7. 2022 marked a year of solid growth for our utilities. We achieved full year adjusted earnings per share of $5.27, above the midpoint of our updated guidance range. These adjusted results exclude our Commercial Renewables business, which was moved to discontinued operations in the fourth quarter. The classification of these assets as held for sale triggered a valuation adjustment of $1.3 billion, which is reflected in discontinued operations and GAAP reported results. This adjustment relates to the combined utility scale and distributed generation businesses and was within our planning range for the sales processes. Moving to our adjusted results for the year.

In the Electric segment, earnings per share increased by $0.36 in 2022, primarily due to higher volumes, favorable weather and rate increases in North Carolina and Florida. Partially offsetting these or higher interest expense and storm costs. Absent storms, O&M was flat to prior year, which was in line with our guidance. In the Gas segment, earnings per share increased $0.07 and was primarily due to the Piedmont, North Carolina rate case and riders. In the Other segment, unfavorable returns on investments and higher interest expense drove results lower by $0.15. Turning to Slide 8. We are reaffirming our $5.55 to $5.75 guidance range for 2023 with the midpoint of $5.65. Within Electric, we expect retail volume growth in 2023 of roughly 0.5%.

We also entered the year with updated rates for Ohio and Florida already in effect and we’ll see growth from 3 Carolinas rate cases as we move through the year. Additionally, we will continue to see growth from the grid investment riders in the Midwest and Florida, namely the Indiana TDISC and Florida SPP plans approved in 2022. Moving to cost mitigation. We’ve identified $300 million of savings in 2023, which is primarily related to rationalizing our corporate and business support cost structures. Examples include streamlining IT support and reducing our real estate footprint. These cost reductions will be realized ratably over 2023 with approximately 75% of the savings being sustainable into future years. Partially offsetting these favorable drivers are higher financing cost as well as depreciation and property taxes on a growing asset base.

Within our Gas segment, growth drivers include the Ohio rate case currently underway, cost mitigation efforts and customer growth, partially offset by higher interest expense. Finally, we expect the Other segment to be unfavorable due to higher interest expense. Turning to retail electric volumes on Slide 9. In 2022, we saw load growth of 2.5%. These strong results were driven by residential customer growth of 1.8%, higher usage per customer from hybrid and remote work and a continuation of the post-COVID rebound in the commercial class. Our total retail load in 2022 was about 2% higher than 2019 pre-pandemic levels. This is equivalent to an average annual growth rate of around 0.5% when smoothing out the year-to-year fluctuations. In 2023, total retail load growth is projected to be roughly 0.5%.

Based on 2022 U.S. Census Bureau data, 3 states within our regulated footprint were in the top 6 for net population migration. This illustrates the robust customer growth experienced in our territories, which we expect to continue in 2023. We expect load growth in the commercial class to moderate this year following 2 years of significant growth. But the upside in industrial as easing supply chain constraints fuel a continued rebound for certain large manufacturers. Longer term, we expect annual load growth to be about 0.5% through 2027. Turning to Slide 10. I’d like to provide an overview of our 5-year capital plan, which has increased to $65 billion. When compared to prior periods, the capital plan has steadily increased as we move further into the clean energy transition.

This increase is net of removing almost $3 billion of commercial renewables capital, including the previous 5-year plan. This means that we’ve increased the regulated plan by approximately $5 billion, resulting in a 7.1% earnings-based CAGR through 2027. While the investment needs of our utilities continue to accelerate, customer affordability remains front and center. Affordability has consistently been a pillar that governs our planning, and we have several tools to help keep rates low and assist customers who are struggling to pay their bill. First, the benefits of our cost mitigation efforts go back to customers over time, easing bill impacts as we recover capital investments. As I mentioned, we expect 75% of our 2023 cost mitigation efforts to be sustainable.

Additionally, we are targeting flat O&M from 2024 through 2027. Our long-term O&M trajectory is supported by smart capital investments within our plan, including modernized equipment and technology investments that will help reduce fuel and operating costs. Next, the Inflation Reduction Act provides substantial benefits for carbon-free resources, including nuclear and solar PTCs and other renewable tax credits. We are beginning to incorporate these benefits and updated resources plans and rate adjustments. Over the next decade, we will fully leverage IRA benefits across all of our jurisdictions in order to maintain low cost for customers as we execute our clean energy transition. Finally, assisting vulnerable customers has always been an area of focus.

But since the pandemic, we worked even more closely with our communities and customers in need. For example, in 2021, we created a specialized team that partnered with agencies across our service territories and help connect customers to nearly $300 million in energy assistance funding over the 2 years. Moving to Slide 11. Our ability to execute our robust capital program is underpinned by a healthy balance sheet, and we remain committed to our current credit ratings. In December 2022, we received $1 billion in cash proceeds upon the closing of the second tranche of the Indiana minority stake sale. We expect to receive proceeds from the Commercial Renewables transactions later this year, which will be used for debt avoidance at the holding company.

Turning to FFO to debt. We ended 2022 below our 14% target, largely due to deferred fuel balances. We have started recovering these amounts through established recovery mechanisms and we’ll continue to file using mechanisms in place for the remaining balances. As we recover deferred fuel costs over the next 1 to 2 years, we expect FFO to debt to steadily improve and return to our long-term 14% target, demonstrating our commitment to our current credit ratings. As we look ahead, about 90% of the electric investments in our capital plan are eligible for modern recovery mechanisms, which is critical to maintaining a strong balance sheet, mitigating regulatory lag and smoothing rate impacts. With the steps we’ve taken to reposition our business and improve our cash flow profile in the years ahead, we are not planning to issue equity through 2027.

Moving to Slide 12. Our robust capital plan, strong customer growth and constructive jurisdictions provide a compelling growth story. And our commitment to the dividend remains unchanged. We understand its importance to our shareholders and 2023 marks the 97th consecutive year of paying a quarterly cash dividend. We intend to keep growing the dividend balancing our targeted 65% to 75% payout ratio with the need to fund our capital. As we begin 2023, we are well positioned to tackle the challenges ahead and look forward to updating you on our progress throughout the year. With that, we’ll open the line for your questions.

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Q&A Session

Operator: . The first question is from the line of Shar Pourreza with Guggenheim Partners.

Shahriar Pourreza: So Lynn, just starting on the Commercial Renewables, it’s good to see, obviously, you guys reiterated ’23. Obviously, the range assumed midyear cash in the door. Just remind us on the EPS sensitivity per quarter from the delay. And I guess, where does this put you within the ’23 range?

Lynn Good: Sure, we’re continuing to target $5.65 and feel very confident with that. As you can expect, as we entered the year, we had a range of expectations around both timing and proceeds from the sale. And what I see now as being kind of a modest delay from midyear to later in the year, I don’t see an impact. I think it’s important to recognize that the growth is primarily driven by our regulated outcomes and the cost mitigation that’s offsetting some of the external headwinds and those are on track as we expected and shared with you third quarter. So confident in the $5.65.

Shahriar Pourreza: Got it. And then just a follow-up on — I know, obviously, the $1.3 billion charge you took for commercial, you’re obviously not the only utility that’s done this. We had a peer took a charge yesterday. Is there anything to read on the ultimate sale price for the assets? I mean, obviously, we noticed word robust “fell off ” the slides. I guess how do we take that charge relative to the ultimate sale price?

Lynn Good: Shar, I appreciate the question. I also appreciate how closely you all read the slides. We weren’t intending to signal anything with the word robust. We feel good about the process. There’s strong interest in the portfolio and we’re moving forward. I think the thing to recognize on an impairment charge, is this an accounting adjustment that’s really driven by the earnings profile of renewables, where a lot of the profit that’s in the early part of the life, you then depreciate it over a longer period of time. So when you make a decision to exit before the end of the useful life, you’ve kind of set yourself up for an impairment. So I would look at it that way. The takeaway is the strategic decision around asset remains unchanged, and we’re on track for proceeds later this year.

Shahriar Pourreza: Got it. Perfect. And then just one quick one for Brian, if it’s okay, on the credit side. Obviously, trying to — the prior plan had a 14% FFO to debt over 5 years. And now you guys kind of stated over the “long term.” ’23 target is 13% to 14% from obviously the deferred fuel balances and 13% is a downgrade threshold. I guess can you just talk on how the rating agencies are treating these deferred fuel balances? And how you’re thinking about future balances? I mean, could another event trigger a downgrade as we’re thinking about the balance sheet capacity?

Brian Savoy: We’ll definitely hit that, Shar, and thanks for the question. We’re working through the deferred fuel balances, through the regulatory mechanisms in place. And that’s what the agencies are looking for. Looking to see, are you filing in line with the regulatory recovery that is established. Or are you making exceptions spreading that recovery longer. We’ve had really good success so far in North Carolina and South Carolina, and we have a couple more filings in front of us, both in Florida and Duke Energy Carolinas, North Carolina. But these are working. The regulators understand our need to recover this in a timely manner from a credit position and the rating agencies are liking what they’re seeing in how we’re executing these plans in accordance with the tools in place.

Lynn Good: And Shar, the only thing I would add to that is we look at this and the agencies look at this as a temporary issue because you can associate it completely with the deferred fuel. And the fact that we have been able to work constructively through recovery mechanisms, and we can actually forecast how that balance is going to decline over ’23 into ’24, it gives us a lot of confidence on the metrics. And of course, as you would expect, we’re in conversations with the rating agencies every step of the way. This regulated portfolio that we have with the cash flows and constructive jurisdictions is really what underpins the credit ratings of the company, and nothing has changed around that risk profile.

Operator: The next question is from the line of Julien Dumoulin-Smith with Bank of America.

Julien Dumoulin-Smith: Thank you for the time and a pleasure chat. Just following — so just with respect to the carbon plan here and obviously, the developments late in the year, you guys had — you addressed it in part in the comments, but I’m just sort of curious, as you think about addressing some of the follow-up items here through the course of this year. Again, what is the flex in the capital plan? What exactly are you assuming today in some of the updates in the multiyear outlook? And specifically, as we’ve talked about before, how could the subsequent updates here impact probably more of the ’24 outlook as you think about puts and takes in the CapEx budget? What could come out of this next

Lynn Good: Sure. And thanks, Julien, for that. I regard the carbon plan order is a very constructive one that has given us real clarity on the near-term investments. So when you think about 3,100 megawatts of solar, 1,600 megawatts of battery storage, that capital plan is pretty well locked in for the Carolinas. We may see some marginal changes, but I would think about those as later in the 5-year period and really in connection with the next update. So I feel really good about the Carolinas. Florida is also on track with the 10-year site plan and SPP and grid modernization. I think where we have potential and even potential upside is in Indiana, where we are earlier in the clean energy transition, moving through that process.

We have estimates in the capital plan, but we’ll be filing for CPCN later this year, and have more advanced dialogue about timing and approach. So I’m very comfortable with the capital plan and if anything, see a bit of upside in Indiana as we continue our clean energy transition.

Julien Dumoulin-Smith: Got it. Actually, since you mentioned it, just to probe a little bit. You said a moment ago, you assume a certain baseline in Indiana already in the latest plan. But as I heard you say a second ago, you’re saying that there’s more likely than not upside bias within that, but you have assumed something in the Indiana

Lynn Good: Yes. We have an estimate. That’s exactly right. We put an estimate in there, Julien, but we’re filing an updated IRP later this month into March, then we’re filing for CPCNs. So that will crystallize more specifically toward the end of this year into 2024, much in the way that the Carolinas has matured as we go through IRP filings. Now we have an order on the carbon plant. So that’s the way I would characterize it. And if anything, I would say our estimate has been on the conservative side.

Julien Dumoulin-Smith: Got it. All right. Excellent. And then any developments or any thoughts around South Carolina here as you think about the opportunities that may exist there? I know, obviously, carbon plan principally think about North Carolina here. Any crystallization of a further alignment here in South Carolina, if I can call it that at all?

Lynn Good: Well, it’s a good question, Julien. And I guess I’d like to step back and just point for a moment to a very constructive and comprehensive settlement that we were able to reach on the South Carolina rate case. I think that’s an indication of just the incredible work that we have been doing with the stake — with the stakeholders to continue constructive dialogue about where the company is going and what we’re trying to accomplish. And I appreciate your sensitivity on the word alignment because what we are trying to accomplish is giving both states the flexibility to put their fingerprints on an energy plan going forward. And we believe we’re making progress on this. We actually had testimony in the carbon plan that laid out a structure that would allow states to opt in or opt out depending on their energy policy, and that is beginning to take some discussion in South Carolina, but that will progress over time.

We believe we operate in an incredibly valuable system, and we’ll work with both states on how to add resources to meet their needs, customer and policy needs going forward.

Operator: The next question is from the line of Steve Fleishman with Wolfe Research.

Steven Fleishman: So just a follow-up question on the Commercial Renewables impairment. The — I think you announced it was for sale in the Q3 call. So is there a reason the impairment was not taken then and is being taken now? Is that because you have more information? Is that something else?

Lynn Good: So Steve, we actually made the decision — final decision to sale in early November and announced it on the third quarter call. So that decision went through a governance process, Board approval, et cetera, in the fourth quarter. And as a result, the impairment goes in the fourth quarter.

Steven Fleishman: Okay. Okay. That’s helpful. And — but it does sound like the impairment — the value that you have on now is consistent with the ranges that you’ve been expecting for the sale process.

Lynn Good: That’s exactly within our planning range, absolutely.

Steven Fleishman: So nothing’s really changed in your planning range. Okay.

Lynn Good: That’s exactly right.

Steven Fleishman: My other question is on the rate cases in North Carolina under the new law, the new multiyear rate plan, how are you thinking about whether you’d be able to settle those cases or that they likely need to — because they are kind of the first under the law and need to go through a full litigated process most likely?

Lynn Good: Steve, I think it’s too early to tell exactly. And you may — if you think back on our history, we have, from time to time, entered into partial settlements where you feel like there are elements of this case that can be agreed and then there are others that the parties believe ought to be put in front of the commission. You should know we’ll explore discussions with all intervening parties through this process. And as we get closer to dates when testimony gets — is ready to be heard and testimonies been filed by all the parties, we’ll begin those discussions. But it’s too early to tell the shape that it will take.

Steven Fleishman: I guess one last thing. The $300 million of O&M reductions, I know that’s, I think, a number that you’ve had before, the 75% sustained. Can you just remind me, is that the same that you said before? Or does that number get

Lynn Good: It is, Steve. No, it’s the same. It’s the same as what we said before. So thank you.

Operator: The next question is from the line of David Arcaro with Morgan Stanley.

David Arcaro: Just on that topic of cost management, could you give your latest level of confidence in hitting the $300 million this year, what you’re seeing in the backdrop in terms of it becoming more challenging, easing up of any of those inflationary pressures this year so far?

Brian Savoy: That’s a good question, David. This is Brian. When we looked at the opportunities across the board last year to really position 2023 in a good spot, we identified areas in our corporate costs and business support that we felt like we could really align service levels with work prioritization. And we did this across the board, but a good example is in IT, right? We have about 1,300 IT systems. Well, not all are mission-critical don’t need to be — have the same level of support as others. So we really stratified our support levels. And we did that across IT, HR, legal, finance, we looked at across the corporate areas and found really structural opportunities that will remain for the long term. And that’s why we feel like a lot of the 75% of the $300 million is sustainable.

And another area that was also very important to the cost reductions was our real estate footprint. In Uptown Charlotte, we’re moving from 4 buildings into 1 new tower. That’s reducing service costs on those assets as well as lease cost and depreciation. So inflationary pressures are not impacting our ability to hit that $300 million target. We’ve contemplated inflation in certain pockets in the portfolio as we look into the spin in 2023 in our planning horizon and feel good about the $5.65 target we have.

David Arcaro: Okay. Understood. That’s helpful. And then I was wondering if you could just talk to — what gave you the confidence in knocking up the CapEx plan for the ’23 to ’27 period. But then also on the rate base outlook, it looked like the 2027 rate base forecast had ticked up a decent amount versus the prior expectations. So I’m wondering if there are any other drivers behind that, too.

Lynn Good: David, as we come to capital planning every year, we take into account where we are with regulatory approval, where we are with integrated resource plans, et cetera. And so we have seen an increase in transmission and distribution investment. If you look at the carbon plant in particular, there’s transmission that’s been approved in order to open up more potential for renewables. And as we get out into ’26, ’27, those numbers also reflect what we expect to mature in subsequent IRP updates and subsequent regulatory approvals. So that’s how I would answer. I don’t know, Brian, would you add anything further?

Brian Savoy: No, I think as we move deeper into the clean energy transition, we expect the capital plan to increase year after year as well. So this is in line with our expectations as we move through the ’20s.

Lynn Good: And I think that’s an important point. As we were talking — thinking back to the generation transition day kind of showing those charts about the 10 years. As we get deeper into the plan, more generation investment begins to show up earlier in the plan, more transmission and distribution. So you’re beginning to see that and you’ll see more of it in ’28, ’29, ’30.

Operator: The next question is from the line of Nick Campanella with Credit Suisse.

Nicholas Campanella: A lot of good questions so far. So I guess conceptually, Brian, when you updated this plan in the third quarter, we were kind of at the height of inflation, interest costs, gas costs, et cetera. And now we’ve obviously seen some of those things roll over here since you’ve given the 5% to 7%. Does that put you in a better spot in the range now, given that dynamic? I’m just thinking long term through the plan here? Any comment that you could give on that?

Brian Savoy: Nick, it is a good question around long-term growth rate. And we feel good about our 5% to 7% growth. And we have a lot of things to figure out. I mean interest rates have moderated to some degree, but they’re still moving up, right? The Fed is still moving it. Fuel costs have been on the downward trend, and we — that’s really good for our customers. But they could move up just as fast as they did in 2022. So right now, we’re sticking to the 5% to 7% growth range and not signaling inside it anymore.

Lynn Good: I think the commodity price is coming down, Nick is a real positive for customers because you think about we still have deferred fuel to collect, but our estimates for cost of fuel in 2023 is coming off and that’s a good thing. So we’re pleased to see that. It’s good for customers. It also takes a little pressure off of interest in financing. So we’ll continue to take advantage of every bit of that.

Nicholas Campanella: I appreciate that. And to your point on the deferred fuel, 80 bps hit to the FFO and the ’23 time frame here, and I acknowledge you have a path to get back to the 14% long term. I guess my question is, do you see sufficient headroom in your metrics at this point for unforeseen events like storms? And just how should we kind of think about the ability for the current plan to just handle any more kind of transient credit hits here?

Lynn Good: We feel very comfortable. The fact that we’ve absorbed $4 billion of deferred fuel and $0.5 billion of hurricane in 2022 alone, I think, is a strong testament to where we are, our scale, our ability to manage resources, et cetera. So we feel comfortable with it. We care deeply about maintaining these credit ratings. We think they’re important and at the right level for the degree of risk in the business, but this is an opportunity that presents itself with the size and scale of our company where we can manage our way through blips of this type. More than a blip actually, $4 billion.

Operator: The next question is from the line of Jeremy Tonet with JPMorgan.

Jeremy Tonet: I just want to round out the Commercial Renewables conversation a little bit, if I could. If there’s any additional color you could provide on the sale such as where book value stands right now, portfolio tax equity position, asset level debt. Just trying to fuse together more on our side. I appreciate that it’s a sensitive time given that you’re selling the assets, but wondering if you could share any more details, particularly as it relates to book value.

Lynn Good: Yes. And Jeremy, let me comment on — we feel good about the process, strong interest in the portfolio. We’re not going to talk any more specifically around valuation. I hope you can appreciate that given where we are in the process. And I don’t know, Brian, if you want to add anything to…

Brian Savoy: Yes. Jeremy, we referenced a $3 billion book value excluding the tax attributes mid-year and we had some projects we continue to invest in for the balance of the year and then took the $1.3 million write-down at the end of the year. So you can kind of walk it down that way if you want to think about book value.

Jeremy Tonet: Got it. That’s helpful. And then I just wanted to kind of pivot a little bit, you involved with a number of emerging technology partnerships, including Honeywell battery, and TerraPower hydrogen pilot. Just wondering which technology here you’re most excited about? And if you were going to move forward 10, 20 years down the road, which one do you think plays a larger part in the Duke portfolio at that time?

Lynn Good: Jeremy, it’s a really good question. It’s a really good question. And one of the reasons we are involved in so many different things is the obstacle for full-scale adoption has a lot to do with which technology can reach commercial scale with a supply chain that will support how much of it we need. I think about our path or climate report through 2050 has us a need of somewhere between 10,000 and 15,000 megawatts of what we call 0 emitting load following resources kind of in that late . So that could be hydrogen. It could be small modular reactors. It could be CCUS, it could be longer duration storage. So the key being, again, though, we’re not going to invest until they’re affordable for our customers, and we can invest at the commercial scale necessary to make a difference.

The small module reactor is something we’re spending time on, and you would expect us to. We are the largest regulated nuclear operator in the U.S. sitting in a part of the world that embraces nuclear as part of the solution. But we also joined with a collection of Southeastern utilities to pursue a hydrogen hub. Because with all that carbon-free generation and all the solar we’re going to have in this area, we think that’s something worth investing in, really, as part of maintaining and preserving the natural gas infrastructure that has been so important to this region. So I know it’s a roundabout answer to the question, but we’re not ready to put our finger on any specific technology as the solution, but we are advancing our work, piloting, advising, working as actively as we can to make sure these technologies are developing at pace so that when we do need them and are ready to invest, there will be something that makes sense for our customers.

Operator: The next question is from the line of Durgesh Chopra with Evercore ISI.

Durgesh Chopra: Just all my other questions have been answered. If I may, I just had a quick clarification on the tax leakage portion of the commercial renewables sale, Brian, does — so the message on the Q3 call was tax leakage is manageable given your other tax losses. I’m thinking about with this write-down, does that impact your sort of tax basis? And are you still saying that — is the message still that the tax leakage is manageable? Or does that — does the impairment charge change that dynamic?

Brian Savoy: Yes. There’s no change to the tax position or a tax basis as a result of this impairment charge, so no change in message. We can manage it.

Operator: Thank you. That’s all the time we have for questions today. I would like to turn the call back over to Lynn Good for concluding remarks.

Lynn Good: Well, thank you all for joining and for your investment in Duke Energy. We appreciate that. We feel like we’ve had a strong finish to the year and excited about 2023. And as always, we’re available, Investor Relations and the senior management team for any further questions. So thanks for joining today.

Operator: That concludes today’s conference call. Thank you for your participation. Please enjoy the rest of your day.