Constellation Energy Corporation (NASDAQ:CEG) Q1 2026 Earnings Call Transcript

Constellation Energy Corporation (NASDAQ:CEG) Q1 2026 Earnings Call Transcript May 11, 2026

Constellation Energy Corporation beats earnings expectations. Reported EPS is $2.74, expectations were $2.54.

Operator: Good morning, ladies and gentlemen, and welcome to the Constellation Energy Corporation First Quarter 2026 Earnings Conference Call. [Operator Instructions] As a reminder, this call may be recorded. I would now like to introduce your host for today’s call, Tim Flottemesch, Vice President, Investor Relations. You may begin.

Tim Flottemesch: Thank you, Daniel. Good morning, everyone, and thank you for joining Constellation Energy Corporation’s first quarter earnings call. Leading the call today are Joe Dominguez, Constellation’s President and Chief Executive Officer; and Shane Smith, Constellation’s Chief Financial Officer. They are joined by other members of Constellation’s senior management team, who will be available to answer your questions following our prepared remarks. We issued our earnings release this morning along with the presentation, all of which can be found in the Investor Relations section of Constellation’s website. The earnings release and other matters, which are discussed during today’s call, contain forward-looking statements and estimates regarding Constellation and subsidiaries that are subject to various risks and uncertainties.

Actual results could differ from our forward-looking statements based on factors and assumptions discussed in today’s material and comments made during this call. Please refer to today’s 8-K and Constellation’s other SEC filings for discussions of risk factors and other circumstances and considerations that may cause results to differ from management’s projections, forecasts and expectations. Today’s presentation also includes references to adjusted operating earnings and other non-GAAP measures. Please refer to the information contained in the appendix of our presentation and our estimates in our earnings release for reconciliations between non-GAAP measures and the nearest equivalent GAAP measures. I’ll now turn the call over to Joe.

Joseph Dominguez: Thanks, Tim. Good morning, everyone. I hope you enjoyed a wonderful Mother’s Day, celebrating the great moms in our lives. Thanks for joining us today and for your continued interest in Constellation. Our prepared remarks this morning will be relatively brief. We spent a good amount of time with you just over a month ago when we shared our business and earnings outlook, so we could be more efficient with your time today. I’ll begin by summarizing the key messages from the business update and then talk about the quarter, some of our generation development activities and the PJM regulatory landscape. First and foremost, I want to remind you that our long-term outlook is compelling with a base earnings growth rate that exceeds 20% through 2029, anchored by highly visible drivers that include the nuclear production tax credit, which grows with inflation, long-term contracts with high-quality counterparties and durable customer margins supported by the nation’s largest commercial and industrial retail platform.

We also have conviction that we could grow the business at a long-term rolling 10% plus base EPS growth rate, which we see as a common characteristic of high-quality and well-valued companies. Further, our outlook is arguably conservative through 2029 with considerable levers to drive upside that are quantified on Page 13 of this deck. You will see that this is an updated version of Page 23 of the business update that we reviewed last month, which so many of our owners told us that they liked. As Shane will cover in more detail, some of the opportunities include additional long-term offtakes for data center customers at our nuclear and gas plants as well as with customers wanting clean, firm and reliable power with price visibility, higher utilization of our gas fleet due to rising around-the-clock demand, positive gearing to higher than 2% inflation through the nuclear PTC construct, and finally, the benefit of higher returns on our strong and growing free cash flow.

The second big story line here is the mix of our base and enhanced earnings. The Calpine business brings high quality, visible earnings to Constellation, supporting our growth outlook and reinforces the value of bringing these 2 companies together. Lastly, I would call out here the free cash flow outlook, which, upon reflection, we could have probably done a better job of when we provided the business outlook, but we’ve provided the updated numbers now on Page 13. Much like the strong EPS growth, we see similar growth in our free cash flow outlook with the ’26, ’27 period producing a forecasted $8.4 billion and the ’28-’29 period rising to $11.5 billion to $13 billion before the levers I just mentioned. We will have significant opportunity to productively deploy capital over the balance of the decade to drive value.

Turning to Slide 6 and the quarterly results. I want to, as I always do, first start out by thanking the women and men here at Constellation for their dedication and for delivering another strong operational and financial performance quarter. We posted first quarter GAAP earnings of $4.49 per share and adjusted operating earnings of $2.74 per share. Based on our performance year-to-date and our outlook for the remainder of the year, we are affirming our full year adjusted operating earnings guidance range of $11 to $12 per share. Shane will cover the details in his section. Since we last spoke, we moved quickly to get back into the market buying our stock in a pretty narrow window. Over the past few weeks, we have successfully repurchased approximately 1.2 million shares at an average price of roughly $285 per share for a total of $335 million of purchases.

These purchases underscore our commitment to disciplined capital allocation and our confidence in the long-term value of the business. The buyback was an intentional statement from management and our Board that we are excited about the growth opportunities ahead, but that at these prices, we see our stock as a compelling use of our cash. We were excited to be named Barron’s 2026 Most Sustainable U.S. Company in the quarter, ranking #1 among the 1,000 largest publicly traded companies in the United States. This recognition is based on an evaluation of more than 230 performance indicators measuring how companies treat a broad range of stakeholders, including their employees, their owners, customers, communities and, of course, the environment.

Being recognized by Barron’s as the most sustainable U.S. company is a very, very big deal to us, and it validates our approach to doing business. At Constellation, we have a culture of doing hard things and doing them well. Despite an increasingly challenging market environment for new development, this quarter, we successfully delivered 2 new generation projects to the grid, demonstrating our ability to execute and deliver when it matters. First, we placed the 105-megawatt Pastoria Solar Project into service. This solar project is next to a combined cycle machine of over 750 megawatts at the same location. And it’s the first part of a combined solar and battery storage project that supports the California Department of Water Resources’ goal of achieving carbon neutrality by 2035.

And it further strengthens Constellation’s leading position as the largest producer of carbon-free energy in the country. Second, we commenced commercial operations at our 460-megawatt Pin Oak Creek natural gas peaking facility in Texas. Designed for rapid startup, Pin Oak Creek will provide critical peak demand support and enhance grid reliability during periods of elevated electricity demand. Together, these projects demonstrate Constellation’s ability, post the Calpine acquisition, to execute on complex development efforts and deliver new generation that meets the evolving needs of both our customers and the grid. On the transaction front, last week, we received PUCT approval of the net metering agreement associated with our Powered Land deal with CyrusOne at the Freestone Energy Center.

This approval is an important signal to the market regarding expectations for colocated projects going forward. Construction is currently underway on the substation that will enable power delivery to the data center, which we expect to be energized in the fourth quarter of this year. Turning to Slide 7. We are making good progress on regulatory clarity in PJM. PJM has put forward a market-based solution to address the incremental capacity needs driven by large customer — large load customer growth, creating a pathway with options for customers to manage their capacity requirements and cost exposure. There have been constructive conversations with stakeholders since the release of the initial proposal. While we expect to see further refinements over the coming weeks, PJM has established a proposed time line for providing clarity on when it expects to vote on the final framework with the goal of submitting the proposal to FERC in June.

Frankly, this is faster than we had hoped. And having this defined time line and a pathway to final rules will provide greater certainty for market participants as they plan and invest. Clarity is critical to unlocking economic expansion across the Mid-Atlantic and Midwest regions by providing a clear path for new large loads to connect to the grid. We think this is a great opportunity for robust economic development in our states, providing the benefits of meaningful construction jobs, ongoing employment, property tax and local community support, while helping to advance the most important economic and national security we have as a country. We are also excited for the customers in our states, both residential and commercial, who are paying the high cost of fixed grid infrastructure.

By bringing on these large loads and by being more dynamic in managing peak usage, we have a real opportunity to improve system utilization and lower the average hourly usage cost for all customers. On the contracting front, customer engagement has varied as PJM works through these policy issues. As I mentioned during our last update, some customers have been willing to continue advancing project discussions and agreement negotiations while others have chosen to pause and wait for regulatory clarity. That’s why I’m pleased to see PJM moving forward so quickly to address this need for clarity. The backstop proposal needs to happen on the time line PJM has laid out, and PJM has to replicate that time line on the colocation document. Last year, there was a prevailing concern that Senate Bill 6 in Texas would significantly constrain data center development in ERCOT.

Instead, once the requirements were established for colocating new load with generation, we began to see transactions come forward. We expect to see the same thing in PJM. The bottom line is that customers want to get their data centers online as quickly as they can. They need regulatory clarity for that to happen. And once the options are understood, they will make the decisions that work for their specific needs. We will continue to work with PJM to help shape the rules to support economic growth, protect residential customers and to stabilize and perhaps actually lower cost for all Americans. Turning to Slide 8. One point that has remained clear is that demand for additional compute and by extension, additional power, has not slowed from hyperscaler customers.

In fact, projected spending levels for 2026 are nearly 75% higher than last year and continue to be revised upward. There is also a growing recognition that reliability must be supported and done in a way that does not burden existing customers. Constellation is well positioned to provide solutions for our customers. We have submitted approximately 5,000 megawatts of new capacity resources into PJM’s interconnection queue, including unique nuclear uprates, new natural gas generation and new battery storage projects. As customers look to contract new capacity to offset incremental demand at peak, we have a diverse set of projects that align well with PJM’s proposed framework and can meet those needs. If a customer prefers to participate in demand response or enable participation through third parties, we can provide those solutions as well through our retail business.

We are highly motivated to identify and provide workable capacity solutions for both customers and for the broader market. Ultimately, our objective is to unlock the full value of our clean, firm energy and associated attributes in a way that benefits all stakeholders. Turning to Slide 9. While we continue to engage with customers and regulators in PJM, it is important to recognize that our opportunity to drive meaningful upside to our outlook extends beyond any single region. We have a demonstrated track record of delivering Powered Land solutions to customers in ERCOT, and we see additional opportunities across our broader fleet to build on that success. Importantly, we have sites with available land and a path to grid interconnection along with a proven ability to successfully navigate the regulatory framework, positioning us well to continue advancing customer solutions.

At our 3 data center projects in Texas, we have customers addressing their reliability commitments both by bringing firm backup generation to cover peak constraints and, in another instance, accepting full curtailability during times of grid stress. These gas adjacent Powered Land deals command a meaningful privilege in their own right, and importantly, they allow full access to the grid, so customers could pair them with purchases of firm carbon-free energy from grid connected nuclear plants, and we are working with customers on those offerings. Now before I turn to Shane, I want to share an observation about this slide and the Pastoria and Pin Oak Creek development projects that I covered back on Slide 6. Obviously, all of this good work was underway at Calpine when we bought the company.

And when we announced the Calpine transaction a little more than a year ago, we talked about the compatibility and complementary nature of the commercial and retail businesses. We talked about Calpine’s industry-leading natural gas and geothermal assets. And of course, we talked about its terrific people. But we also shared with you that in the future we saw coming, Calpine would help to supplement Constellation’s existing skills in new natural gas, solar and battery storage development as well as Constellation’s abilities in connection with natural gas data center transactions. And as you reflect on the regulatory requirements in PJM and ERCOT and in other places, I trust that you can now see how supplemental development and commercial capabilities will help us to unlock the value of Constellation’s amazing and unique fleet of nuclear natural gas assets in a way that help our customers and America grow while stabilizing and potentially reducing costs for everyday American families.

With that, let me turn the call over to Shane to talk a little bit more about our financial performance in the first quarter. Shane?

Shane Smith: Thanks, Joe, and good morning, everyone. Beginning on Slide 10. For the first quarter, we earned $4.49 per share of GAAP earnings and $2.74 per share of adjusted operating earnings. This is $0.60 per share better than the first quarter of last year and consistent with our expectations. Higher earnings for the quarter can mostly be attributed to the EPS accretion from Calpine. As a reminder, our guidance included approximately $2 per share of accretion for Calpine on a full year basis. In addition to incremental earnings from Calpine, results benefited from higher capacity prices in PJM and lower stock-based compensation expense. These positives were partially offset by more planned nuclear fueling — refueling outage days compared to the first quarter of last year, lower ZEC pricing across state programs and higher cost to serve load associated with winter storm Fern.

While the business performed well operationally through the storm, the extended nature of the event caused the grid operator to call on operating reserves to support system reliability. Those incremental ancillary charges resulted in higher cost to serve customer load. Looking to the full year 2026, we are affirming our adjusted operating earnings range of $11 to $12 per share that we provided on March 31. Moving to Slide 11. Our nuclear performance was once again strong this quarter. We generated 40 million megawatt hours of firm and emissions-free energy from our operated nuclear plants with a capacity factor of 92.3%. Our capacity factor included the aforementioned impact of more planned outage days than typical in the first quarter. Our combined cycle and cogeneration fleet generated 23 million megawatt hours with a 47.1% capacity factor.

It’s important to note that operational metrics differ across these asset types. The thermal fleet is subject to dispatch signals that vary by weather and system conditions. Operationally, the CCGT and cogeneration fleet had a forced outage factor of 5.1%, meaning our units delivered when called upon nearly 95% of the time. As large load customers, including data centers, come online, we believe our strong operations will be a differentiator in meeting that increased demand and higher utilization of existing assets will benefit customers over time. Turning to Slide 12. Our commercial team continues to support our customers by delivering tailored energy solutions that address their evolving needs. In our business and earnings outlook, we showed customer margins in our base earnings assumptions, those that we view as highly visible and predictable, that were higher than our previous disclosures for both the power and gas portfolios.

This margin expansion has been driven by 3 factors: first, traditional C&I power margins have expanded; second, the growing customer demand for carbon-free solutions we spoke to in our outlook adds incremental margin; and third, incorporating the Calpine retail portfolio further enhances our outlook, reflecting a higher mix of tailored products in attractive high-value markets. The scale of our customer solutions platform has delivered durable value and growing earnings for over a decade. With the addition of Calpine’s retail business, we now serve approximately 275 million megawatt hours of electricity and 800 Bcf of natural gas annually to customers across 40 states. Importantly, most of that volume is through commercial and industrial customers, including over 80% of the Fortune 100.

These are the customers most likely to recognize the value we bring as a strategic partner with the ability to tailor solutions to meet their needs as they are the customers most likely to place a premium value on the firm clean megawatts produced by Constellation. On Slide 13, in our business and earnings outlook, we outlined expected free cash flow before growth of $8.4 billion across 2026 and 2027, and how we plan to deploy our cash flow within our established capital allocation framework over that 2-year period. Today, I am focusing on our forecast for free cash flow before growth in 2028 and 2029 and providing transparency about how the optionality that we highlighted for our earnings also applies to free cash flow. I think given our track record of success in allocating capital, it’s important we highlight projected free cash flow before growth that we expect will be available for accretive deployment.

Over 2028 and 2029, we expect to generate between $11.5 billion and $13 billion of free cash flow before growth. Using the midpoint of that range, that represents approximately a 45% increase relative to the $8.4 billion we expect in ’26 and ’27. On the right side of the slide, we reflect the same opportunities we shared last month, now including what each lever could provide in growing free cash flow before growth on an annual basis starting in 2029. These figures are illustrative and not intended to necessarily be additive, but they provide useful context for how the optionality we have highlighted will also drive incremental free cash flow. All of this upside for both earnings and cash sits on top of a highly visible and durable base with meaningful growth that exists today, reinforcing the strength of the core business and the optionality we have to create additional long-term value.

Turning to Slide 14. As Joe mentioned, we got to work right away deploying capital towards share buybacks under our increased authorization, utilizing $335 million to repurchase about 1.2 million shares, and we will continue to execute opportunistically. Our capital allocation framework remains consistent and disciplined. We are committed to maintaining our strong investment-grade credit metrics, investing in growth opportunities across the portfolio that meet our double-digit unlevered return targets, maintaining and growing the dividend at 10% per year and returning excess capital to our owners. Supported by strong and growing free cash flow, we will continue to apply this framework thoughtfully and intentionally. With that, I’ll turn it back to Joe.

Joseph Dominguez: Thanks, Shane. Good job. So to close, we continue to work hard to deliver value for our owners and the communities in which we operate. For nearly 2 years, we’ve navigated regulatory uncertainty alongside of our customers and other stakeholders as they seek to connect large load projects to the grid, and meaningful progress has been made. ERCOT’s moved the ball forward, and now it’s time for PJM to move the ball forward. And we see that once regulatory clarity exists, projects move forward. The light now is clearly visible at the end of the tunnel in PJM, and we’ll continue to work constructively with policymakers and market regulators to ensure we arrive at a framework that makes sense for all stakeholders while also helping to facilitate potential cost relief for American families.

Our customers are keen to get moving in PJM, and we’re working with them to make that happen. And while we await final clarity, our focus remains firmly on execution. We’ll continue to operate our assets at world-class levels and deepen our engagement with customers across our platform, including those in the data economy to secure durable, premium-priced agreements for our clean, firm and reliable generation. I want to thank you again for your time this morning, and we’ll open it up to questions now.

Operator: [Operator Instructions] Our first question comes from David Arcaro with Morgan Stanley.

Q&A Session

David Arcaro: I was wondering if I could get your latest views on the power market, maybe ERCOT, in particular. Just curious your interpretation and viewpoint here as to the weakness in the forwards even despite some of the very strong data center activity in the pipeline that we’re seeing there. What do you make of that and thoughts on the evolution of that market?

Joseph Dominguez: David, I think the short answer — I’m going to turn this over to Andrew Novotny here for a moment, but — in a moment, but I think the short answer on ERCOT is it’s about timing. We’ve seen that market be all over the place in the last, call it, 90, 120 days in terms of pricing. And the real questions are how much load and when. While there’s been a lot of talk about data center and other development activities in ERCOT, it’s kind of important to remember that, that load isn’t yet on the system, it’s getting built. And so the timing of that is going to be one driver. And then there is, I think, as you know, an incredibly wide range of forecasted additional potential growth in the ERCOT market and when that comes in and how it’s interconnected remain the questions. We think ERCOT is undervalued, and we don’t think that the prices in the outer years, in particular, make a great deal of sense. But Andrew chime in.

Andrew Novotny: Yes, Joe, I agree with all that. Maybe just to add some, just to get specific, when Joe says the market is undervalued, we’re really focused on the ’28, ’29 and beyond period of time. That’s really where the load growth can come. So there’s been over 400,000 megs of large loads in the queue. Obviously, we don’t expect anything near that. But the forward market beyond ’29 to us, appears like something that’s only expecting 10,000 to 15,000 megs. So if we see numbers like 30,000 megs, we believe that the market will see upward pressure. In the meantime, in the short term, we’re not surprised by the weakness, and we’ve been well hedged and protected against it.

David Arcaro: Got it. Understood. That’s helpful. And then maybe separately, wondering if you might be able to just comment on the current level of state support in Pennsylvania, just a direction around favorability towards data center activity. We saw the governor recently sending a letter to the regulated utilities in the state. Wondering kind of what the posturing is, maybe does that shift perspectives on how they see the wholesale market and general impression of support for data centers in Pennsylvania?

Joseph Dominguez: Yes. Look, I — even that letter, which obviously pertain to regulated utilities and not to entities like Constellation, reference the importance of the competitive market. So I think, look, Pennsylvania is very supportive, has been very supportive of competitive market solutions. The Governor was clearly one of the leaders in terms of the cost cap in RPM and was likewise one of the leading voices in the large load bring your own generation kinds of discussions that we see now as part of this regulatory proceeding in PJM. But with the exception of those things, continues to be very supportive under the right circumstances in data economy development and reindustrialization in Pennsylvania. The Governor has spoken about the importance of the jobs and the economic development for Pennsylvania to be a leader in AI and other technologies under the right conditions. So we see it as continuing to be very constructive, David.

Operator: Our next question comes from Steve Fleishman with Wolfe Research.

Steven Fleishman: So I guess, first on Crane. Any updates on the time line there? And just what should we be watching for to suggest that maybe it comes on sooner than the 2031 connection?

Joseph Dominguez: Steve, it will come on sooner. I mean, what we’re talking about is getting full capacity credit for the asset. So I don’t want anybody to be under the misconception that the plant won’t start sooner. In terms of getting the full capacity credit, right now, the ball is actually in FERC’s court. We have filed, as you know, to transfer the CIRs from Eddystone to Crane, which we think will facilitate a ’27 capacity credit. We’re also continuing to work every day with the utilities on speeding up the transmission interconnection process. Kind of normally is the case that they start off with a pretty long time line and shorten that up, and we’re working with the utilities involved here to shorten up these projects so that we can get on sooner. So that is really the update. We’ll know more when we hear back from FERC. David, do you have anything? I’ll ask David Dardis, if he’s got anything more on that.

David Dardis: No, I just see, we’re hoping to get a response back from FERC in the June, July time frame. You also saw that PJM acknowledged the importance of the requested waiver without taking any substantive position otherwise. So everything Joe said, I just want to double down on, and really this is about who bears responsibility for the congestion being ultimately relieved by the RTEP projects and Eddystone does not need those CIRs. It will continue to perform for the DOE order as an energy-only resource, but we think that there’s a clear path for FERC to approve the CIR transfer to meet the 2027 deadline.

Steven Fleishman: Okay. Great. And then other question, just it was good to see the buybacks. We do have this first lockup coming up for the Calpine holders the end of June. Any kind of sense on where their heads are at? And should we read in anything into the fact you were willing to buy stock kind of before that kind of came up?

Joseph Dominguez: Look, I don’t think you should read anything into the fact that we bought early. I think I covered that in the prepared remarks. We thought that was a very compelling price to be buying back our shares. We’re going to be pretty careful about kind of signaling how different investors may be acting in this space. But Shane, why don’t you provide whatever color you can?

Shane Smith: Yes. Just to remind folks of the context here, in the consideration for Calpine, we issued 50 million Constellation shares to the owners, 25 million are — the lockup expires on June 30, 2026, and the remaining 25 million are June 30 of 2027. And so when we contemplated the $5 billion authorization, we certainly wanted to have flexibility to the extent there could be a transaction of note around the lockup. But to Joe’s point, it’s really conditional upon what the current owners of the shares want to do. And so just in the nature of being prudent, I won’t speak on their behalf around their intent, but we’ll have the flexibility if there’s something that makes sense for both sides.

Operator: Our next question comes from Shar Pourreza with Wells Fargo.

Shahriar Pourreza: Joe, maybe just starting on PJM. You noted that some hyperscaler conversations stopped, some continued. Peers have been a little bit more open to working on deals in parallel with the FERC and PJM process. Is anything preventing having a bilateral deal in hand before the RBP? I mean, do you need to match new capacity plus existing capacity to get a contract?

Joseph Dominguez: No. First of all, there’s 2 questions there, Shar. Nothing is stopping us from moving forward on a deal now. And I think as I indicated during the last update, we see clients that are interested in doing that. And they figured they’ll manage whatever comes out of the regulatory process with the tools that they have or other purchases. For other clients, they kind of want to see what this looks like, what the cost implications are, what our solutions look like, how our solutions pair up with other things we’re looking at in the market before they’re going to move forward. So I don’t think this is a full stop. I do think it is a pause to see what this looks like and then a quick resumption hopefully, of those conversations.

Shahriar Pourreza: Got it. Okay. Perfect. And then just maybe a follow-up. There’s obviously a substantial amount of cash to allocate $5 billion buyback authorized, $8.4 billion of free cash through ’27 and even higher run rate thereafter. How does that kind of tie into the $0.50 of upside sensitivity? And do you anticipate incremental investment opportunity to be more accretive versus the $0.50? Are the alternatives on asset acquisitions limited at this point just given market power? Just an overall capital allocation update would be great.

Joseph Dominguez: Sure. I’m going to turn it over to Shane. Look, I don’t know that — I don’t see it as a competition, given our free cash flow capability at the company. We’re going to have organic investment opportunities, over 10% IRRs. We’ve talked about a number of those things like the uprates on prior calls. Those things are going to move forward. But we’re also going to be in a position where if our stock is trading at a level that we think is inconsistent from a value standpoint with the future that we think we’re going to be able to accomplish with all the different levers that are in front of us and capabilities, then we’re not afraid to buy back our shares. But I think at the end of the day, it’s going to be a mixture of all those things. Shane?

Shane Smith: Yes, Joe, you said it well. I think, Shar, what I would say about the $0.50 is where we wanted to ensure that there was a range or some flexibility is the nature that those investments could take. To the extent that you’re bringing development online, it obviously has a longer period of time until it becomes accretive, whereas if it’s M&A, obviously, in the case of Calpine of being of scale and you’re adding $2 per share of EPS a year later. So I think we just wanted to be thoughtful and measured and help people think through what the range of outcomes would be as you deploy capital at the right return profile, and that could take a number of different shapes and sizes. But the $0.50 was intended to be illustrative based on assumptions you can make on that capital allocation.

Operator: Our next question comes from Nicholas Campanella with Barclays.

Nicholas Campanella: I wanted to ask — I appreciate the free cash flow clarity out to ’29. I mean, could you maybe just talk a little bit about the cash conversion between EBITDA and free cash through ’29? And as you get some of these projects up and running, like Crane is going to ramp and a few other things in the back end of the plan, how do you kind of think about cash conversion?

Shane Smith: Nick, it’s Shane. I mean it’s not going to change materially from what you’ve seen historically with regard to the nature that most of the cash contribution is from the nuclear fleet. So if you think about the appropriate assumptions around cash tax, maintenance CapEx, how you’re accounting for fuel, the conversion won’t look significantly different than historical. What I would highlight is, to the extent we’re able to execute those levers identified in that conversion between the EPS and free cash flow, a lot of that you’ll see drops to the bottom line. Those aren’t requiring incremental investments and so a lot of those are really just a tax adjustment from the earnings to cash flow.

Nicholas Campanella: Okay. And then I wanted to ask just on the new capacity resources. You’re highlighting about 5 gigawatts into the interconnect queue between uprates and natural gas and battery storage. And just how does that kind of compare to where you were in the March 31 update? I know you spoke about some idle turbines then and — are you willing to kind of commit to more new build in this plan here? And how should we kind of think about the threshold for that?

Joseph Dominguez: Look, I think it probably is a good bit more just because we’re adding in some of the Calpine capability. But at the end of the day, in terms of how we’re going to utilize it or what’s going to move forward, I think we’re also waiting to see a little bit more from PJM in terms of what projects will qualify and also where they are in the queue process. But I don’t know that at this point we’re in a position to commit anything until we get a little bit more detail from PJM on the backstop proposal and obviously get further along on contracts that might call for some of our resources as part of the bilateral agreements we enter into.

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

Julien Dumoulin-Smith: Just maybe to follow up a little bit about the conversation we were having about the cadence of things. How do you think about Calvert here versus Limerick or versus any other permutation? Is there — sort of given the evolution of the regulatory dialogues you’ve had, is there a specific direction? Obviously, we heard more about Calvert in recent weeks from you all at the Analyst Day. How would you just set expectations around that? And then to go back a little bit to this conversation. Is there like a specific ratio that you guys think about in terms of additionality? Or how does the curtailment demand response piece? You guys just did this net metering thing in Texas, for instance, but how does that play out into kind of firming up a specific process to be able to move forward on this?

Joseph Dominguez: Yes. Julien, I’m going to give you a bit of a nonanswer on the first one on who’s going to get through the finish line first as between any different site. We mentioned Calvert because as folks probably undoubtedly saw later on during the course of the day when we did the business outlook, there was a newspaper article on it. And so we wanted to share some thoughts before the newspaper article came out. But otherwise, we’re going to let our customers announce transactions when they’re ready to announce transactions as opposed to us doing it here. In terms of how folks are going to manage it, Julien, and what the ratio of new to existing might be, I think we’re going to see a mix is my personal opinion. We talked a little bit about the Texas deals during our prepared remarks today.

And I think that’s a pretty good indicator of how wide this range could be from folks who are completely comfortable with using backup generation or other curtailment tools that they might have to manage. Keep in mind that these are sophisticated buyers that, in many instances, are already out there buying things like battery storage and solar and other things. So sometimes they’re coming into these transactions with some existing contracts. And you remember when Jim McHugh was talking a couple of years ago about our CFE, our original CFE agreements, the first one with Microsoft, in fact, it was exactly that situation. Somebody came in through the door and said, “Look, we’ve got this big portfolio, we want you to manage it and then set it up so that we have really round the clock, 24/7 environmental attributes.” So we have clients that will walk in with that capability, and I think all the way to clients that are going to want things like demand response and backup generation.

But the mix is going to be interesting because I think it’s going to be different for different customers in terms of their ability to handle curtailment and their willingness to handle curtailment. I’ll make another point, and I think the data centers themselves are going to increasingly be able to manage some of the curtailment risk by moving data economy jobs around. So as you think about the U.S., as data centers proliferate in different regions, I think it’s going to give them the ability to identify jobs that don’t either have to happen at peak hours of energy consumption or could be shipped away to other data centers in different regions of the country that might not be experiencing a reliability issue at that moment in time. So I just think the landscape is changing, and I think we’re going to see a mixture of solution sets that is going to be really broad all the way from people being able to manage curtailment by shifting jobs and doing that sort of thing, depending on that data center, all the way to people who are going to need backup generation for every single megawatt of the data center in terms of peaking capacity.

And so I just think any attempt to kind of generically say this is the ratio is kind of a fool’s errand at this point based on what we know of the market.

Julien Dumoulin-Smith: Yes. I totally hear. I respect that. And just as a quick follow-up. You talked about Clarity a lot in the prepared remarks and otherwise here. Is there a specific threshold docket you’re looking for to really unlock things? At the same time, I heard you in the Q&A comments saying, “Look, other customers are working for it on this anyway.” Is there a moment that you think that you get this docket resolved and that could unleash some of this? Or again, as you suggested earlier, some of them and some may or may not be waiting for said deadlines?

Joseph Dominguez: Yes, again, I don’t want to speak for all of them. I think just the mere filing will be clarity for some because they will anticipate given where the FERC has been on it. And I think the FERC clearly has an appetite for moving quickly here, right? So I think the details of the filing themselves have been helpful already. But I don’t know. At some point in time, some of these guys may wait all the way to the end of the backstop proceeding. If they have a colocation idea that they’re working on, it might need to wait for the colocation filings and for FERC’s final order on that. The important thing is we’re seeing speed here that is really, I’ve been doing this 20-plus years with PJM, and I’m seeing this stuff move at a speed that is really unprecedented.

The only other time I saw anything move with this kind of speed was when we had the — some of the RPM changes when PJM first adopted the internal rules that allowed them to move forward in an expedited way without a stakeholder vote. So we’re seeing a commission that anxiously wants to solve this. They understand the importance of getting this right, but also the importance of the data economy to America, and that’s very, very clear. The administration is clearly focused on this. And we’re seeing PJM act very quickly here. I would like to see the colocation implementation date, which PJM had indicated was 2029, I’d like to see that moved up. And I think on that, we’re aligned with the signals that are coming out of FERC, but stuff is moving very quickly, and I expect we’ll have clarity on all these issues by the end of the year.

Operator: Our next question comes from Jeremy Tonet with JPMorgan Securities.

Jeremy Tonet: I was wondering if I could ask a question, a bit of a high level to start off here. Looking at the white paper last week out of PJM, Powering Reliability Through Market Design, wondering if you were able to provide any initial reactions to paths A, B and C. Just any high-level thoughts would be welcome.

Joseph Dominguez: Let me turn it over to David Dardis for his thoughts on that.

David Dardis: Jeremy, thanks. So we certainly appreciate PJM issuing the white paper and acknowledging the need to revisit its market rules, and frankly, it’s commitment to competitive markets for ensuring reliability. A lot of what’s in that white paper are things we’ve talked to PJM for a number of years about including, in particular, optimizing the energy and reserve markets together and better reflecting value in the energy market as opposed to as much reliance as it’s had on capacity markets for a number of years. So we think that’s very positive. In addition, we’ve been very supportive. We’ve been talking for at least 2 years to anyone who will listen to us about bilaterally contracting and firming up their supply given what we saw on the horizon around rising energy prices.

And so we think that’s also quite positive. As it relates to option B and the differential reliability, I think that one needs some more — we need some more time to digest that and think about what that could potentially mean. We certainly agree with the flexibility of load being a very important solution going forward in the marketplace. But some sort of a permanently put in the rules, the discriminatory treatment of different loads around the reliability, allocating reliability on that basis, I think that — there’s some real legal questions impeded in that one, and that’s going to require more consideration. But if we can start moving more quickly, in particular, on energy market reform and the reserve market and co-optimizing that, that we see is quite positive.

Joseph Dominguez: And Jeremy, that’s something we’ve urged them to do for a long, long time. And frankly, something that PJM has put on the back burner to its detriment. Look, there are 2 things that got us into the pickle we’re in. One is capacity prices were ridiculously low because we weren’t considering the actual capacity capabilities of the resources adequately. That has changed. And we saw a pop up in capacity prices. That should have been managed better all along. The other thing that should have been managed better all along is that more of the revenue should have been recognized in the energy market, putting less strain on the capacity market, which, as we’ve learned, could be punitive to residential customers. So it’s good to see in this white paper that these issues are back in front of PJM.

That’s where they need to be. Competitive market solutions are going to be the right answer. These markets need to enable that quickly. And so hopefully, PJM actually follows up with real action on the white paper, but they’re going to be pressed. I mean, I think this commission is very hot to trot on getting clarity and getting this stuff settled very quickly. And so PJM’s got to keep moving this issue forward.

Jeremy Tonet: Got it. That’s very helpful. Pricing scarcity is difficult.

Joseph Dominguez: It is.

Operator: Our final question comes from Nick Amicucci with Evercore ISI.

Nicholas Amicucci: Just wanted to get a sense just on the near-term kind of nuclear uprates, how near term are those? And when are we kind of — what’s kind of baked into the 2029 assumptions?

Joseph Dominguez: All right. So the ones that are in plan are Byron and Braidwood as a general rule. And is there anything else in the plan right now?

Shane Smith: None of the uprates. The capital is out the door, but nothing is showing up as EPS accretion in ’29. 2030 is the earliest that they’ll add to EPS.

Joseph Dominguez: Except for Byron and Braidwood that are in plan.

Nicholas Amicucci: Perfect, perfect. And then just given kind of the strong results in the first quarter, right, you guys have mentioned they were relatively in line with your expectations. But historically, we’ve seen kind of the biggest question mark around the first quarter. So just wanted to get some type of sense, I guess, where — what would you guys need to see kind of going forward to get kind of more confidence in the upper half of the range and understanding you just spoke a little over a month ago.

Joseph Dominguez: Look, at least another quarter. Look, we — when you think about the timing of our business update call, we were well into the first quarter. So we had a pretty good sense of how the quarter was going to come out when we set guidance initially. All right. Operator, are there any additional calls or questions, excuse me?

Operator: I’m showing no further questions at this time. This does conclude the question-and-answer session. I would now like to turn it back to Joe Dominguez for closing remarks.

Joseph Dominguez: Well, just thanks again, everybody, for your interest in Constellation. We had a good first quarter, thanks to our folks. We’ll continue to strive to execute through the balance of ’26, and we’ll talk again in about 90 days. Operator, we’ll end the call.

Operator: Ladies and gentlemen, thank you for participating on today’s call. This concludes today’s program. You may disconnect. Everyone, have a great day.