Title

Presentation

NextEra Energy, Inc. beats earnings expectations. Reported EPS is $0.99, expectations were $0.969.

Operator: Good morning, and welcome to the NextEra Energy, Inc. First Quarter 2025 Earnings Conference Call. All participants will be in the listen-only-mode. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Mark Eidelman, Director of Investor Relations. Please go ahead.

Mark Eidelman: Thank you, Dorwin. Good morning, everyone, and thank you for joining our first quarter 2025 financial results conference call for NextEra Energy. With me this morning are John Ketchum, Chairman, President and Chief Executive Officer of NextEra Energy; Brian Bolster, Executive Vice President and Chief Financial Officer of NextEra Energy; Armando Pimentel, President and Chief Executive Officer of Florida Power & Light Company; Rebecca Kujawa, President and Chief Executive Officer of NextEra Energy Resources; Mark Hickson, Executive Vice President of NextEra Energy; and Mike Dunne, Treasurer of NextEra Energy. John will start with opening remarks, and then Mike will provide an overview of our first quarter results.

Our executive team will then be available to answer your questions. We will be making forward-looking statements during this call based on current expectations and assumptions, which are subject to risks and uncertainties. Actual results could differ materially from our forward-looking statements if any of our key assumptions are incorrect or because of other factors discussed in today’s earnings news release and the comments made during this conference call in the Risk Factors section of the accompanying presentation or in our latest reports and filings with the Securities and Exchange Commission, each of which can be found on our website at www.nexteraenergy.com. We do not undertake any duty to update any forward-looking statements. Today’s presentation also includes references to non-GAAP financial measures.

You should refer to the information contained in the slides accompanying today’s presentation for definitional information and reconciliations of historical non-GAAP measures to the closest GAAP financial measure. With that, I’ll turn the call over to John.

John Ketchum: Thanks, Mark, and good morning, everyone. NextEra Energy is once again off to a strong start for the year, delivering solid first quarter results. Adjusted earnings per share increased by nearly 9% year-over-year, reflecting solid financial and operational performance across FPL and Energy Resources. FPL placed into service 894 megawatts of new solar and Energy Resources originated approximately 3.2 gigawatts of new renewables and storage projects. We continue to see strong demand for new sources of generation across all sectors of the U.S. economy. For perspective, we expect more than 450 gigawatts of cumulative demand for new generation between now and 2030 in the United States. To meet this demand, we believe it’s important to exercise what I describe as energy realism and energy pragmatism.

Let me explain. Energy realism is about embracing all forms of energy solutions and understanding the demand for electricity in the United States is here now, and it’s not slowing down. Frankly, it’s unlike anything we’ve ever seen since the end of World War II. Energy pragmatism is about recognizing some technology is ready at scale today and other technology needs more time to get there, and there will be significant trade-offs with regard to the timing and cost of each. Today, renewables and battery storage are the lowest cost form of power generation and capacity. And we can build these projects and get new electrons on the grid in 12 to 18 months. We should be thinking about renewables and battery storage as a critical bridge to when other technology is ready at scale like new gas-fired plants.

We expect 75 gigawatts of new gas to come online between now and 2030. That is significant for sure, but nowhere close to meeting the over 450 gigawatts of total generation we believe are needed. It’s also important to understand that gas-fired plants will come online at a higher cost than renewables and storage. That’s because gas turbines are in short supply and in high demand. It’s also proving difficult to reestablish the highly skilled workforce required to build these complex power plants. Gas-fired combined cycle plants rely on approximately 1,000 workers across dozens of niche trades. We’ve learned EPCs are hiring thousands of extra people to address high washout rates with some workers leaving earlier for higher-paying jobs building, for example, LNG terminals, data centers, semiconductor chip manufacturing facilities and other industrial facilities.

Other workers are showing up to job sites without the necessary skills. All of this puts upward pressure on prices and the time to build gas plants. It’s why the cost to build a gas-fired plant has tripled in the last few years and is poised to increase even further due to tariff exposure. We believe nuclear will continue to play an important role in meeting demand. But again, we need to be practical about when that will happen. There are limited opportunities to restart shuttered nuclear units. Two are underway in our sector, and we continue to evaluate bringing our own Duane Arnold facility in Iowa back online. Beyond those limited opportunities, SMR technology is still 10 years away at scale in the best of scenarios and at a much higher price point than gas-fired generation.

There’s also an option to defer coal retirements to meet demand. But even if we kept online every coal plant in America slated to retire, it would only add approximately 40 gigawatts to the grid. And many are months away from retirement or are already slated to be converted to gas, again, far short of the over 450 gigawatts needed between now and 2030. Bottom line, don’t take this as picking winners and losers. It’s not nor can it be. America is going to need all forms of energy to meet this enormous demand. But we need to be practical about when technologies will be available at scale and how much they’ll cost when they show up, all of which factors into how Americans pay – how much Americans pay on their electric bill each month. This is why energy policy in Washington is so important and why we cannot isolate ourselves to just a couple of technologies like gas and nuclear, which are much more expensive than they’ve ever been and take far longer to build.

We say all this as a company in our space that does it all. NextEra Energy is the quintessential all forms of energy company. We know renewables and storage because we’re a world leader in the space. We know gas because we operate the largest gas-fired fleet in America and have built more gas-fired generation than anyone over the last 2 decades. We know nuclear because we operate one of the largest fleets in the United States. And we know how to serve growth because we’ve been doing it for decades across the United States and in Florida, which brings me to Florida Power & Light Company. FPL is proof that embracing all forms of energy works, especially during periods of growth. Florida is the nation’s third largest state and people continue to move here.

In fact, we’ve added more than 1.3 million new customer accounts in the last 20 years, making us roughly 30% larger than we were in 2005. Despite the incredible growth, FPL consistently delivers high reliability while having customer bills significantly below the national average. And we continue to deliver what we believe is the best customer value proposition. As we celebrate our 100-year anniversary at FPL, our vision remains the same, to continue making smart capital investments for the benefit of our customers, be an industry leader on cost and deliver high reliability and outstanding customer service while keeping bills low for our customers. To continue driving customer value and to power Florida’s growth, we’ve been deploying the most cost-effective option for customers, solar and storage and now have approximately 8.4 gigawatts of solar and batteries installed across Florida.

In all, our generation strategy has saved customers more than $16 billion in avoided fuel costs since 2001. Looking ahead, at FPL, we continue to see growth on the horizon, and we are projecting to add roughly 335,000 customer accounts through 2029. To continue to meet growth and reliably serve customers, FPL plans to invest nearly $50 billion from 2025 to 2029 and add more than 25 gigawatts of new generation of battery storage by 2034. On February 28, we submitted testimony and detailed information for FPL’s 2025 base rate proceeding. The overall proposal for our 2026 through 2029 base rate plan is consistent with the test year letter filed in December. The stability of multiyear plans has allowed FPL to focus on efficiency in the business, which is critical to keeping customer bills low and has enabled FPL to maintain a strong balance sheet, which allows for consistent access to the capital markets.

We look forward to the opportunity to showcase our long-term track record of providing low bills and high reliability for Floridians and our plans to build an even more resilient energy future for Florida. We believe FPL is strategically positioned as Florida remains one of the fastest-growing states in the U.S. and we plan to meet Florida’s long-term growth outlook with investments in generation, transmission and distribution infrastructure, which we believe will further enhance our best-in-class customer value proposition. Energy Resources had a strong quarter, originating approximately 3.2 gigawatts of new renewables and battery storage projects. This marks the fifth time over the past 7 quarters that Energy Resources has added more than 3 gigawatts to its backlog, a sign of the continued strong demand for new generation.

Energy Resources also had its largest solar origination quarter and largest solar and battery storage origination quarter ever, again, demonstrating the strong demand for renewables and storage because they are low cost and can be deployed now. Assuming we achieve the midpoint of our development expectations range, Energy Resources will be operating in more than 70 gigawatt generation and storage portfolio by the end of 2027. Taking FPL and Energy Resources together, we believe NextEra Energy has the most comprehensive power generation business in the world and is well positioned to capitalize on long-term growth prospects. There has been ample discussion about tariffs these last few weeks. While this has forced some companies to look at their supply chains for the first time, we’ve spent the last 3 years diversifying and domesticating ours to strategically position our supplier relationships to manage potential disruption.

For perspective, we’ve dramatically diversified where we source our solar panels. As a result, we don’t source solar panels from countries impacted by the antidumping and countervailing duty tariff rates announced earlier this week. Plus, we source our wind turbines from the U.S. with manufacturing in Florida. And because of our buying power, we have been able to significantly shift tariff risk to suppliers. After discussion with our suppliers, we currently estimate Energy Resources has less than $150 million in tariff exposure through 2028 on over $75 billion in expected capital spend. That’s less than 0.2% of potential impact to our capital spend before exercising contractual trade measure protections in our contracts with customers. Size and scale matter more than ever in today’s environment.

Suppliers want us to be repeat customers, and our customers want certainty, certainty that comes with doing business with an industry leader like NextEra Energy that has a long track record of delivering on its commitments. Once we work with our customers, we expect our $150 million tariff exposure to be significantly reduced, potentially down to zero. Still, we continue to look for ways to further mitigate trade risk and use our supply chain management capabilities to create new opportunities. Our team had the foresight last year to secure arrangements to purchase U.S.-made batteries for a significant portion of our backlog with the remainder of the batteries sourced outside of China where tariff exposure is contractually allocated to the supplier.

Batteries are already more than two times cheaper than gas-fired plants available now and much more flexible to interconnect to the grid. Taking most tariff exposure off the table for our customers in need of battery storage solutions is a big win and a way for us to meet demand while keeping bills low for customers. Our battery sourcing strategy gives us optionality and favorable pricing through our already secured domestic battery supply contracts. In short, our tariff exposure on batteries is expected to be negligible and we expect our domestic sourcing options to create significant competitive advantages for us and our customers going forward as we originate new battery storage projects. Finally, we now have nearly $37 billion of interest rate hedges in place that allows us to flexibly manage interest rate exposure over the coming years, including interest rate hedges on 100% of our backlog and a large portion of our upcoming maturities.

In fact, we entered into swaps as part of our programmatic hedging strategy when interest rates sharply declined in early April after reciprocal tariffs were announced, putting our hedged risk-free rate at roughly 3.9%. Our interest rate sensitivity is included in the appendix of today’s presentation. Before I hand it over to Mike, I want to briefly touch on last month’s planned leadership transition announcement. As we announced in March, after 18 years of service to NextEra Energy, Rebecca Kujawa will be retiring. Rebecca has had an incredible career at our company and has brought a strong strategic perspective and leadership approach to everything she’s accomplished. Brian Bolster will succeed Rebecca as President and CEO of NextEra Energy Resources.

Brian has done an amazing job as our CFO and has the ideal combination of capabilities, experience and customer relationships to lead one of America’s largest energy infrastructure development companies. Mike Dunne has been promoted and will succeed Brian as CFO of NextEra Energy. Mike has deep financial acumen and vast knowledge of the energy industry, having spent his entire career in this sector. Both Brian and Mike are effectively transitioning into their new roles. We believe we have the best team in the industry with a track record of delivering day in and day out. There is no team better equipped or better positioned to help meet this unique moment. That’s not to say it will be easy. The enormous electricity demand in the United States creates challenges and not getting this right risks higher power prices.

But this is where NextEra Energy shines. We thrive when the stakes are high. We lean into complexity. It’s what differentiates us. So many companies are approaching this moment from a standing start. We’ve been running this marathon for decades, and I couldn’t be more optimistic about our prospects to deliver for our customers with the outstanding team we have in place. With that, let me turn it over to Mike, who will review first quarter results in more detail.

Mike Dunne: Thanks, John. For the first quarter of 2025, FPL’s earnings per share increased $0.07 year-over-year. The principal driver of this performance was FPL’s regulatory capital employed growth of approximately 8.1% year-over-year. We continue to expect FPL to realize more than 10% average annual growth in regulatory capital employed over our current rate agreement’s 4-year term, which runs through 2025. FPL’s capital expenditures were approximately $2.4 billion for the quarter, and we expect FPL’s full year capital investments to be between $8 billion and $8.8 billion. For the 12 months ending March 2025, FPL’s reported return on equity for regulatory purposes will be approximately 11.6%. During the first quarter, we utilized approximately $622 million of reserve amortization, leaving FPL with a balance of roughly $274 million.

As we previously discussed, FPL historically uses more reserve amortization in the first half of the year. We expect this trend to continue this year. This quarter, FPL placed into service 894 megawatts of new cost-effective solar, putting FPL’s owned and operated solar portfolio at over 7.9 gigawatts, which is the largest utility-owned solar portfolio in the country. In April, FPL filed its annual 10-year site plan, which continues to indicate that solar and storage are the most cost-effective options for customers to add reliable grid energy and capacity over the next decade. The 2025 plan projects the need for over 17 gigawatts of cost-effective solar generation across our service territory over the next 10 years. And as a complement to FPL’s planned solar additions, FPL is planning to deploy over 7.6 gigawatts of battery storage, which provides cost-effective capacity.

With this plan, we expect to increase FPL’s solar mix from approximately 9% of our total generation in 2024 to approximately 35% in 2034, while continuing to provide customers with low cost and reliable energy. As John mentioned, on February 28, we submitted testimony and detailed supporting information for FPL’s 2025 base rate proceeding. We are requesting a base rate adjustment of approximately $1.5 billion starting in January 2026. $927 million in January 2027 and a solar and base rate adjustment or SoBRA mechanism to recover revenue requirements for solar and battery storage projects in 2028 and 2029. With the proposed base rate adjustments and current projections for fuel and other costs, we believe that FPL’s typical residential customer bill will grow at an average rate of about 2.5% from January in 2025 through the end of 2029, which is expected to result in FPL’s typical residential bill being approximately 25% below the projected national average and more than 20% lower than our typical bills 20 years ago when adjusted for inflation.

Florida Public Service Commission has established a schedule for this proceeding, beginning with quality of service hearings in May and technical hearings in mid-August. The proceedings would likely conclude in the fourth quarter with staff recommendation and commission rulings on revenue requirements and rates. We look forward to the opportunity to present our case to the commission this summer and are focused on achieving a balanced outcome that supports continued smart investments for the benefit of our customers. Key indicators show that Florida’s economy remains healthy. Florida continues to be one of the fastest-growing states in the nation and had 3 of the 5 fastest-growing U.S. metro areas between 2023 and 2024. FPL had a strong quarter of customer growth, with the average number of customers increasing by nearly 108,000 from the comparable prior year period.

FPL’s first quarter retail sales increased by approximately 1.8% year-over-year. After taking weather into account, first quarter retail sales increased by roughly 0.6% on a weather-normalized basis from the comparable prior year period, driven primarily by continued favorable underlying population growth. Now let’s turn to Energy Resources, which reported adjusted earnings growth of nearly 10% year-over-year. Contributions from new investments increased $0.12 per share year-over-year, primarily reflecting continued growth in our power generation portfolio. Our existing clean energy portfolio declined $0.03 per share during the quarter associated with various puts and takes in the business. And the comparative contribution from our customer supply business decreased by $0.01 per share.

Contributions from NextEra Energy Transmission increased $0.01 per share year-over-year. All other impacts decreased by $0.05 per share, driven by higher interest costs of $0.06 per share, half of which are related to new borrowing costs to support our new investments. As we previously disclosed and as we deemphasize the business, we have reclassified gas infrastructure to include gas pipelines and existing clean energy and upstream gas infrastructure in customer supply. Gas pipelines and upstream gas infrastructure each had a $0.01 decline in the quarter. Energy Resources originated approximately 3.2 gigawatts of new renewables and storage to the backlog. With these additions, our backlog now totals roughly 28 gigawatts after taking into account 0.7 gigawatts of new projects placed into service since our last earnings call.

This highlights the continued strong growth for renewables and storage. We’re also excited to announce our first solar repowering project, which we expect to be completed in 2026. Going forward, we plan to include both wind and solar repowering megawatts in the newly updated repowering line of our development expectations. Our backlog additions represent the diverse power demand that we are seeing across industries. Roughly 40% of our backlog additions are driven by commercial and industrial customer demand, while 60% are driven by demand from power companies. As evidenced by our nearly 1 gigawatt additions, our customers continue to choose battery storage as the lowest cost, ready now solution to meet their capacity needs. Turning now to our first quarter 2025 consolidated results.

Adjusted earnings from Corporate and Other decreased by $0.03 per share year-over-year. Our long-term financial expectations remain unchanged. We will be disappointed if we are not able to deliver financial results at or near the top end of our adjusted EPS expectation ranges in 2025, 2026 and 2027. From 2023 to 2027, we expect that our average annual growth in operating cash flow will be at or above our adjusted EPS compound annual growth rate range. We also continue to expect to grow our dividends per share at a roughly 10% rate per year through at least 2026 off of a 2024 base. As always, our expectations assume our caveats. That concludes our prepared remarks. And with that, we will open the line for questions.

Operator: We will now begin the question-and-answer session. [Operator Instructions] The first question comes from Steve Fleishman with Wolfe Research. Please go ahead.

Steve Fleishman: Yeah. Good morning. Thank you. So first, just related to the tariff disclosure you provided, which sounded very good. The – the battery portion where you’re moving a lot domestic, I assume that means you’re also getting domestic battery cells as part of that. Is that right?

John Ketchum: The way the contract works, we get certain components – Steve, sorry, I cut off there for a minute. Let me start over. So with the battery – the domestic battery contract that we have entered into, it is assembled here in the United States. There are certain components that come in from outside the United States, but because it’s assembled here and has enough concentration here in the U.S., it qualifies for domestic content. And we have contractual protections in the agreement in place regarding the qualification for domestic content. And also to the extent that there is any tariff exposure related to any imported parts or components related to those batteries, those are protected as well and backstopped by substantial credits. So that is a domestic contract, and that’s the way investors should think about it.

Steve Fleishman: Got it. Thanks for that. And then just in terms of the exposure on the tariff exposure, which you know, you’ve talked for a long time about making sure that you’re protected there with your suppliers. Obviously, one of the issues can be making sure that the suppliers still supply while they absorb tariffs. Just how do you feel about the supplier health to kind of meet the commitments as well?

John Ketchum: I feel good. I feel very good for two reasons. One, given the buying power that NextEra has, suppliers don’t want to disappoint, and they want to make sure they fall through. They’re looking at this as a long game for their business. Second, the way our contracts are set up with our credit protections in the agreement, there’s a very strong incentive to fall through on those commitments. And then the third point that I would make is that, the U.S. still remains an extremely attractive market to suppliers across the globe, meaning that they have a lot of margin when they deliver into the U.S. And when we put those three things together, I lose no sleep over whether or not our suppliers will fall through on their commitments and deliver into the U.S.

Steve Fleishman: Yeah. Got it. Makes sense. And then just on the – switching to a lot of focus these days on IRA, obviously, and changes and specifically on transferability. And so maybe just one clarification on transferability. In the event, hypothetically, if it were to go away in the future in a bill, do you – would it still be applicable for existing assets that were done under transferability as well as safe harbor assets on transferability?

John Ketchum: Yeah. So I mean, there was a recent piece of legislation that was brought forward that basically, you know, the Fedorchak [ph] bill, I’ll use that as an example to answer the question. So on the Fedorchak [ph] bill, the way it was structured is that you’d see tech neutral eliminated through a phase down, but with transferability eventually being phased out there. However, under the non-tech neutral portion, there would be an ability to continue the safe harbor for 4 years and transferability is left in place there. So it all comes down to the drafting Steve, at the end of the day, that’s how that bill was drafted. It would depend on the ultimate outcome and drafting of future bills. But let me just make a couple of comments on transferability.

We spent a lot of time obviously advocating for tax credits and transferability for good reason. And the reasons are, I think, well known by investors. Gas has its limitations in terms of availability for the reasons I went through in the prepared remarks. They’re a lot more expensive. Gas turbines have been hit by tariffs, too, and a lot of folks don’t talk about that, which is actually going to – I think we had put the proxy at 2,400 a kW at our Development Day. It’s probably closer to 2,600 to 2,800 today when you factor in tariffs, gas turbines have actually been hit harder than, I think, solar or wind or storage in that regard. And so we need a bridge. And that bridge has to come from renewables and storage because we have all this demand today.

It’s got to be met by something. And the ability to transfer credits, it goes hand in glove with the credit itself. You have to be able to monetize the credit to be able to get the benefit back to the customer. And I’ll use a couple of examples. I mean, utilities, for example, right? And this is one of the things that we continue to stress in Washington. Utilities historically have struggled to use tax equity financing. Commissions won’t approve it. It’s – you have to sell half the plant to qualify for tax equity financing. And so how do you get the benefit, which we calculate to be a 12% increase in household income to the ultimate utility customer without the ability to transfer the credit. Nuclear, I’ll use as an example. So with nuclear, a tax equity structure doesn’t work, right?

There’s no bank that’s going to take a 50% ownership interest in a nuclear plant. And so you have to have transferability for nuclear as well. And nuclear is going to play an important part of our future. It’s definitely a focus of this administration. 45X as well. If you didn’t have transferability on credits for wind, solar, storage, nuclear, 45X becomes very difficult, right? How do you stimulate all these investments, 80% of which are going into Republican jurisdictions, when you’re trying to convince a CEO to build a manufacturing facility under 45X, but if the credit is not there with the ability to transfer it on the back end for wind, solar, battery storage, the demand for the product is not there either. And so what’s the incentive to invest billions of dollars in the manufacturing facility under a 45X credit.

So when you put all of these things together, credits and transferability go together. You have to – you can’t have one without the other. That’s the message we’re bringing to Washington. It’s one that’s being well understood. I think the evidence lies in the fact that we just had 21 house representatives, Republican House Representatives sign on to a letter saying, don’t touch the credits, don’t touch transferability. We had 4 senators say the same, you know, sign on to a very similar letter. They get it. They get the 2 go together. Will it be a little bit of a bumpy ride as we maybe see some proposed bills? Sure. But I think at the end of the day, folks in Washington understand that transferability and tax credits are hand in glove and go together.

You have to have an ability to monetize the tax credit.

Steve Fleishman: Great. Thank you very much.

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

Julien Dumoulin-Smith: Hey, John team, thank you all very much. And it’s congrats – congrats again on all the new roles here. Very well deserved. John, maybe just to start with a little bit of a more mundane question. You’re talking about going to the higher end of the range here at near [ph] Do you want to talk a little bit about what the contributing factors are there for ’25? And then I’ve got a quick follow-up on what you just said there.

John Ketchum: Yeah. So when I think about higher end of the range, I start with the first quarter results, right? I mean we’re already out of the gate at 9%. And we have a business plan that we feel good about, feel good about executing against. And I don’t think there’s a whole lot more to say about that.

Julien Dumoulin-Smith: Awesome. Thank you. And then look, I really appreciate the details on transferability. I know folks have been very keen to hear from you guys on that. Related here, can you speak a little bit on the timing dynamics on when and how that ultimately will work? You say in your remarks, once we work with our customers, how do you think about the impact 150 from a timing perspective on ’25 versus is that really going to get to that zero in ’26? It seems like this is sort of an assumption that principally the tariff impact is going to impact customers with higher PPAs and you’re going to go back to them today, perhaps like what we saw before with maybe some of the COVID impacts.

John Ketchum: So Julien, your question is on tariffs, right, not transferability.

Julien Dumoulin-Smith: Yeah, sorry. Yeah, sorry. No, I thank you on the transferability.

John Ketchum: So let me make sure I got focused on transferability. You pivoted tariffs. Can you clarify your question on tariffs, just so I understand the question.

Julien Dumoulin-Smith: Yeah. The timing of that, right? So you talk about supply chain, you say once you work with your customers, how do you think about the time line for working with your customers? And is the reason for your tariff exposure to be fairly low principally because you are passing along those costs to your customers in revised PPAs? Or do you have existing contractual terms?

John Ketchum: Yeah. So let me take those in pieces. Let’s just start with the supplier first. So when we look at our entire backlog, right? And we look at our projected Q2 originations, and we look out at the development expectations that we’ve told investors, we think that we’re looking at around $150 million of exposure on tariffs. That is based on the contractual protections we have in our existing contracts with suppliers and the discussions that we have had with them since Liberation Day on April 2. So that’s the first piece. So that works you down to $150 million. Then the point we were making in the prepared remarks is that not only do we have the ability to shift tariff risk to suppliers and supply contracts, which I just covered, we also have trade measure protection provisions in our customer contracts.

So we believe we got a really good shot at working with our customers to take that $150 million exposure down significantly and perhaps even down to zero if we use the track record we had around circumvention, a lot of lessons learned there. And these are rights that we already have embedded in our agreements. And so when I think about where we stand, I feel very good about tariffs. It’s just not going to have much of an impact at all on our business.

Julien Dumoulin-Smith: If I can clarify quickly, the reason there’s 150 is because you have to go back and clarify the contract?

John Ketchum: The reason that it is 150 is that there are certain risk-sharing mechanisms in contracts. Most of the contracts, the supplier takes all the risk. Some of the contracts, they take almost all of the risk, except for a small sliver that we work through with them.

Julien Dumoulin-Smith: Got it. All right. Thank you guys very much. Thank you, John.

John Ketchum: And Julien, I want to make one more point, and I want to make sure folks understand this from the remarks. That’s $150 million on $75 billion of CapEx. That’s less than 0.2%. And we feel like we’ve got a good shot at getting that to zero.

Julien Dumoulin-Smith: Incredible. Honestly.

John Ketchum: And final point I’ll make is, and Steve asked me a little bit about it, but there’s been a lot written about battery exposure. We don’t have battery exposure. Full stop. We do not have battery exposure. We are really well positioned. We entered into a domestic contract. We have actually a real opportunity rather than a risk around batteries.

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

Nick Campanella: Hey, good morning. And thanks for taking the question. So maybe just to close the loop on the tariff discussions, just where do you think returns are from an IRR perspective or an ROE perspective? These protections that you have in place versus your competitors should make you more competitive, I would think. Does that boost your returns? Or do you see these kind of remaining flat in the post-tariff world? Maybe you could address that.

John Ketchum: Yeah, I mean – yeah, I mean, great – that’s a great question, Nick. So I look at it a couple of different ways. I mean, first of all, we’re in great shape on our returns for all the obvious reasons we just covered. So I don’t think I need to spend time on that. I look at this as a huge opportunity for us because we compete again against a lot of small developers, and they don’t have the buying power or the leverage in contracts to be able to shift risk like we can. We started looking at this 3 years ago. We’ve been at it. We didn’t just wake up on November 6 and say, oh my God, what do we do about our supply chain? I mean we’ve been thinking about this for years. And so we put the right things in place. This is going to create a lot of opportunity for us.

So if circumvention is any example, what happened in circumvention is a lot of small developers blew themselves up, couldn’t satisfy their commitments with their customers and a lot of demand came our way. And so I would expect – that’s my point around opportunity that given the position that we’re in around tariffs, I expect a lot of opportunity to come our way as small developers just aren’t in the position we are. They’re trying to absorb a significant amount of risk, particularly those that are – that have entered into contracts for batteries, because they probably are buying from Chinese manufacturers and don’t have domestic contracts and don’t have the position that we have.

Nick Campanella: Thanks for that. And then just maybe a quick update on where you stand in the Duane Arnold contracting opportunity. I think you were working through an engineering study beforehand. How is that kind of progressing? And how have discussions been in terms of getting a contract for this site? Thanks.

John Ketchum: It’s going great. We continue to make a lot of progress at Duane Arnold. We have seen no showstoppers there and continue to see a lot of demand for generation from the project. So I think it continues to be an opportunity that’s exciting for us. And look, we continue to work it as we move forward.

Nick Campanella: Thank you.

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

Jeremy Tonet: Hi. Good morning.

John Ketchum: Good morning.

Jeremy Tonet: I just want to touch base, I guess, on the GEV partnership and if there’s any update that you can provide to us granted it’s recent since you talked about the Developer Day, but just wondering, any updated thoughts to share there?

John Ketchum: Yeah. I mean things with – under the framework agreement continue to advance. We’ve been doing work together on the customer origination side. As a matter of fact, we hosted an event last week that we call Deploy following Development Day, where Scott and I jointly hosted a number of companies across various sectors. And very fruitful, and we continue to try to advance opportunities on that front, particularly around large-scale load.

Jeremy Tonet: Okay. Great. Thanks. And maybe just kind of continuing with this a little bit more. I just wanted to see, I guess, you talked a lot about gas development time line for new turbines. But just as we look in the outer years here, just wondering how you think, I guess, gas power factors in for hyperscalers specifically, I guess, how conversations are going there, given decarbonization goals, but the attributes that gas can offer as well? Just any updated thoughts there would be great.

John Ketchum: Yeah. It’s interesting because we talked a lot about this at Development Day. I mean there’s three things we shoot for, right? One is just achieving the development expectations. I’ll call it kind of the, the status quo plain vanilla business that we advance every quarter. The second is large load, and that kind of falls into two camps. One is behind the meter discussions and the second is front of the meter discussions. And we continue to see a strong preference by hyperscalers for front of the meter solutions, which means ultimately a 3-way conversation, right, between us, investor-owned utilities and the hyperscaler because the hyperscaler wants two things, right? They want the reliability that comes with being interconnected to the grid that you don’t get from behind the meter.

And two, they want the optionality of being able to monetize power if need be, which also comes by being interconnected to – to the grid. So that’s kind of how I see the market moving forward. We also do continue dialogue around behind the meter. There’s a premium, obviously, that has to be paid for the additional redundancy you have to build on the generation side. But for some, that’s worth pursuing because the grid could be difficult to access in certain parts of the United States, can take 5, 7 years. And is the additional premium for redundant generation worth the avoided cost of not having to go through trying to get interconnected. But even in those situations, they’re looking for a path ultimately to be interconnected to the grid. And from a gas standpoint, which is really your question, definitely something that they are looking at as part of the solution.

But they also remain observant and cautious about wanting to understand what the carbon offset is to the emissions off the plant, which is, I think, where our skill set comes in – comes to bear perfectly because we can, through VPPAs and other arrangements provide a nice combination of gas-fired generation together with renewable solutions that provide a nice large-scale fix that can leave the site essentially carbon neutral or close to carbon neutral at the end of the day, which is very attractive to these customers. And I think that is why we are uniquely positioned to serve that market in partnership with the terrific relationships that we’ve been able to build with investor-owned utilities over the last 20 or 30 years and with the strong relationships we have with the hyperscale market.

So more to come on that.

Jeremy Tonet: Got it. That’s helpful. I’ll leave it there. Thanks.

Operator: Our next question comes from David Arcaro with Morgan Stanley. Please go ahead.

David Arcaro: Hey, good morning. Thanks so much. I wanted to go back to transferability just for a quick follow-up there. Wondering what the contingency plan might be if there were changes or restrictions on the use of tax credit transfers. What would the financing alternative be as you think about your overall kind of holistic financing plan?

John Ketchum: Yeah. Great question. So as we look and if you think about our company over 2 decades before 2022, we had – we used tax equity to finance our tax credits, and we able to do that in a very programmatic and good basis. If we look today, we are seeing a flight to quality from tax equity providers coming to us where they’re looking because our projects get done on time, because they perform. And what we’ve seen over the course of the last 2 years is essentially a doubling of the tax equity providers looking to work with us. Also, a key piece of our transfer program allows us to pick the best project returns between transferability and tax equity. When it comes to PTC projects, the returns can be higher in times of transferability, but from a credit perspective, essentially the same outcome.

So as we work through, we’ve done this for 20 years. We’re seeing tax equity come to us. And we’re – so we’re not saying that there will be no impacts. We feel very good about where we sit from a financing perspective for transferability.

David Arcaro: Got it. Okay. That’s helpful. And then I appreciate the comments you gave to Jeremy’s question. I was wondering maybe a bit higher level, what are you seeing in terms of renewable demand trends from tech customers, specifically in data center opportunities? Has there been, I guess, any change in the interest there or the load growth or demand growth that you’re seeing from the data center side of things?

John Ketchum: Short answer is no change. We continue to see a lot of appetite for renewables and it fits perfectly with the discussion that we continue to have on the GE Vernova side around providing gas-fired generation as a potential solution as well. But they remain very focused too on renewables, right? They’re ready now. They’re low cost. They’re an offset for gas if they ultimately decide to go that route in a part of the country that doesn’t have excess grid capacity and the load studies taking too long to complete. And when I look at the demand and the outlook in the renewable sector going forward, and we always are looking a quarter out or so. I mean, we just continue to see strong demand across the board and with hyperscalers being a nice size part of that.

David Arcaro: Okay. Excellent. Thank you.

Operator: The next question comes from Carly Davenport with Goldman Sachs. Please go ahead.

Carly Davenport: Hey. Good morning. Thanks so much for taking the questions. Maybe a higher-level one. Just as you think about the backlog additions, can you talk a bit about the 2024 to 2027 plan relative to the additions for post-2027 delivery? Do you see any risk around project slippage beyond the current plan into 2028 plus just given the more uncertain macro environment and potentially more complex contract discussions? Or you still feel confident in the execution there?

John Ketchum: Yeah, Carly, I mean good question. So maybe I’ll start just with circumvention and remind folks that when we saw circumvention, we did see some shifting out in demand, right? And that’s impacted, I think, our – some of the near-term development expectations with us forecast to come in the low end of the range on the ’24, ’25 numbers. You can see that in the development forecast write-up. But then we were also able to push those projects in the ’26, ’27, ’28 and some of the out years. I think that dynamic was more specific to circumvention than it is here. I think here, there’s just so much demand and the need for electrons right now where customers just can’t afford to wait. And gas is such a long-term solution.

I mean, we’ve gone up from 4.5 years to build a combined cycle unit to 6 or longer. And so needing the electrons now, I think that is foreseeing more near-term demand. Obviously, some of the impact too will ultimately depend on where we come out with Washington, but you’ve heard my comments there.

Carly Davenport: Great. That’s really helpful. Thank you. I’ll leave it there.

Operator: The next question comes from Bill Appicelli with UBS. Please go ahead.

Bill Appicelli: Hi. Good morning. Just a couple of questions on the utility. The 10-year site plan that you guys filed, how should we think about that impacting the capital expenditure program relative to the $34 billion to $37 billion, does that have any impact on that? And or is it sort of post that? And should we assume a higher run rate than the sort of 8.8 to 8.9 that you’ve outlined for ’26, ’27?

Armando Pimentel: It’s Armando, Bill. Good morning. I don’t think you think about it any differently. The CapEx plan that we filed in our rate case for the next 4 years is roughly $50 billion of CapEx, right, over the next over the next 4 years. The 8.8% or so that you just highlighted is roughly in line with what our expectations would be over the next 4 years. And it’s driven by making sure that we continue to do the best thing for our customers. We expect 335,000 new customers over the next 4 years in the FPL area, and that drives a lot of investment, one, and then the additional investment, part of that $50 billion is to make sure that we can continue to make our customers’ value proposition better. So I think it’s more of the same.

Bill Appicelli: Okay. And then regarding the rate case, is settlement still a preferred outcome here? And is that window of time ahead of those technical hearings in August?

John Ketchum: I think settlement is always something that’s on the table. Obviously, it takes 2 sides to – in our case, since there’s a number of interveners, more than 2 sides to come together to get to, for us, a conclusion that’s good for our customers, right? This is all about our customers and making sure that we can get the best outcome for them long term. If you look at historically, excuse me, where we’ve had settlements, they’ve generally been anywhere from 6 weeks before the rate case is supposed to start, which in this case would be mid-August to right before, right after the actual rate case. So if there is going to be a settlement, then that’s the likely outcome. Certainly, it could happen outside of that time. It could happen at any time. But our focus right now is really on putting together the best case that we can for our customers starting mid-August.

Bill Appicelli: Okay. And then just one last quick one. The 11.6% ROE, given the amount of surplus amortization that was utilized, I mean, should that trend a little bit lower over the balance of the year? Or is the expectation that, that can be maintained?

John Ketchum: So we’re required at the beginning of the year to file with our commission and let them know what our expectations are for the year. Obviously, that can change. You saw that change last year when we lowered it. But our expectation is that 11.6% is about right based on the expectations that we have for normal weather this year. We’ll obviously take a look at that every quarter, but 11.6% is our expectation for the year right now.

Bill Appicelli: Great. Thank you so much.

Operator: Thank you. This concludes our question-and-answer session and our conference. Thank you for attending today’s presentation. You may now disconnect.