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DATE

Monday, May 11, 2026 at 10 a.m. ET

CALL PARTICIPANTS

  • President and Chief Executive Officer — Joseph Dominguez
  • Chief Financial Officer — Shane Smith
  • Executive Vice President and General Counsel — David Dardis
  • [Unspecified Senior Management — Analyst Q&A responses]

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TAKEAWAYS

  • GAAP EPS -- $4.49 per share for the quarter, showing a material contribution from Calpine integration.
  • Adjusted Operating EPS -- $2.74 per share, up $0.60 per share compared to the prior year period.
  • Full-Year Adjusted Operating Earnings Guidance -- Affirmed at $11 to $12 per share, reflecting confidence in execution and visibility on current performance.
  • Share Repurchases -- Approximately 1.2 million shares were repurchased at an average price of $285 per share, for a total value of $335 million.
  • Free Cash Flow Forecast (2026–2027) -- Management forecasts $8.4 billion for the two-year period ending 2027.
  • Free Cash Flow Forecast (2028–2029) -- Projected to rise to $11.5 billion to $13 billion before discretionary growth initiatives.
  • Nuclear Generation -- Plants produced 40 million megawatt-hours with a 92.3% capacity factor; more planned outage days impacted this figure versus the previous year.
  • Combined Cycle and Cogeneration Fleet -- Generated 23 million megawatt-hours at a 47.1% capacity factor, with a 5.1% forced outage factor.
  • Customer Scale Post-Calpine -- The company now serves 275 million megawatt-hours of electricity and 800 Bcf of natural gas annually to customers in 40 states; more than 80% of sales are to Fortune 100 companies.
  • New Generation Projects -- The 105 MW Pastoria solar project and 460 MW Pin Oak Creek natural gas facility both came online during the quarter.
  • PJM Interconnection Queue -- Submitted approximately 5,000 MW of new capacity resources, including nuclear uprates, new natural gas, and battery storage projects.
  • Recognition for Sustainability -- The company was named Barron's 2026 most sustainable U.S. company during the quarter.
  • Regulatory Progress -- PJM is working toward a June FERC submission for new capacity market rules, aiming to create clarity for large-load customer interconnections.
  • Net Metering Approval -- PUCT approved the net metering agreement for a data center project at Freestone Energy Center; power delivery substation is targeted for Q4 energization.
  • Dividend Growth Commitment -- Management reaffirmed a target of maintaining and growing the dividend at a 10% annual rate within the capital allocation framework.

SUMMARY

Management confirmed guidance and articulated further free cash flow and earnings growth visibility, highlighting optionality from new long-term contracts, inflation-linked revenue, and broad customer demand across multiple geographies. Executives described progress in regulatory channels—particularly PJM's movement on capacity market reforms and the positive signal from Texas PUCT—as accelerating timelines for major grid interconnection projects. Operational updates focused on two newly commissioned large-scale generation projects, as well as successful capital deployment via share repurchases and an updated capital allocation framework emphasizing double-digit unlevered returns and opportunistic buybacks. Strategic integration with Calpine expanded both customer reach and asset diversity, strengthening the platform's ability to tailor solutions for commercial clients, including hyperscale data centers. Management characterized demand from hyperscale customers as rapidly rising, citing "projected spending levels for 2026 are nearly 75% higher than last year and continue to be revised upward," leading to expanded project submissions in the PJM queue and ongoing negotiations for bilateral agreements even as regulatory clarity develops.

  • Executives stated, "our outlook is arguably conservative through 2029 with considerable levers to drive upside," referencing quantifiable opportunities for additional earnings and free cash flow not included in base guidance.
  • Shane Smith said, "Over 2028 and 2029, we expect to generate between $11.5 billion and $13 billion of free cash flow before growth," describing a 45% increase at the midpoint compared to the prior period.
  • Joseph Dominguez described ERCOT forward market prices beyond 2029 as "undervalued" and not reflective of possible future load growth from queued projects.
  • The company highlighted ongoing work with customers to provide solutions across different reliability needs, noting "a broad mixture of solution sets" and flexibility as regulatory developments evolve.
  • FERC and PJM were both cited as moving with "unprecedented in my 20+ years with PJM," which management views as critical to unlocking additional capital deployment and customer contracting.

INDUSTRY GLOSSARY

  • PJM: A regional transmission organization (RTO) that coordinates the movement of wholesale electricity in parts of the Eastern United States.
  • FERC: Federal Energy Regulatory Commission; oversees interstate transmission of electricity, natural gas, and oil in the U.S.
  • Capacity Factor: A measure of a power plant’s actual output over a period compared to its maximum possible output.
  • CCGT: Combined Cycle Gas Turbine; a technology combining gas and steam turbines to improve efficiency in power generation.
  • PUCT: Public Utility Commission of Texas; oversees utility regulation in Texas.
  • CIR: Capacity Interconnection Rights; rights to inject capacity into the grid, necessary for market participation and recognition of resource contributions.
  • ZEC: Zero Emission Credit; a state subsidy program to support nuclear power by compensating for carbon-free output.
  • RTEP: Regional Transmission Expansion Plan; PJM’s planning process to ensure regional transmission system reliability and economic efficiency.

Full Conference Call Transcript

Joseph 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 Energy Corporation and its 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 materials and comments made during this call.

Please refer to today's 8-Ks and Constellation Energy Corporation'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 will now turn the call over to Joseph Dominguez.

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 Energy Corporation. 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 will 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%+ base EPS growth rate, which we see as a common attribute 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 many of our owners told us 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 storyline here is the mix of our base and enhanced earnings. The Calpine business brings high-quality, visible earnings to Constellation Energy Corporation, supporting our growth outlook and reinforcing the value of bringing these two companies together. Lastly, I would call out the free cash flow outlook, which upon reflection we could have probably done a better job highlighting when we provided the business outlook, but we have 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 2026–2027 period producing a forecasted $8.4 billion, and the 2028–2029 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 six and the quarterly results, I first want to thank the women and men here at Constellation Energy Corporation 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 narrow window. Over the past few weeks, we have successfully repurchased approximately 1.2 million shares at an average price of approximately $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 number one among the thousand 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 big deal to us, and it validates our approach to doing business. At Constellation Energy Corporation, 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 two new generation projects to the grid, demonstrating our ability to execute and deliver when it matters. First, we placed the 105 MW Pastoria solar project into service. This solar project is next to a combined cycle machine of over 750 MW at the same location, and it is 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 Energy Corporation's leading position as the largest producer of carbon-free energy in the country.

Second, we commenced commercial operations at our 460 MW 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 Energy Corporation'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 seven, 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-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 timeline 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 timeline 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 nation. 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 is why I am pleased to see PJM moving forward so quickly to address this need for clarity. The backstop proposal needs to happen on the timeline PJM has laid out, and PJM has to replicate that timeline on the colocation docket. 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 stabilize and perhaps actually lower costs for all Americans. Turning to slide eight, one point that has remained clear is that demand for additional compute and, by extension, additional power has not slowed from hyperscale 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 Energy Corporation is well positioned to provide solutions for our customers. We have submitted approximately 5,000 MW 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 nine, 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 three 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 meaningful value in their own right and, importantly, they allow full access to the grid, so customers can 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 six. 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 that in the future we saw coming, Calpine would help to supplement Constellation Energy Corporation's existing skills in new natural gas, solar, and battery storage development, as well as Constellation Energy Corporation's abilities in connection with natural gas data center transactions.

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 unlock the value of Constellation Energy Corporation's unique fleet of nuclear and natural gas assets in a way that helps 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 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 is 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 three 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 to 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, and they are the customers most likely to place a premium value on the firm, clean megawatts produced by Constellation Energy Corporation. 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 two-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 is 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 2026 and 2027.

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; 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 will turn it back to Joe.

Joseph Dominguez: Thanks, Shane. Good job. To close, we continue to work hard to deliver value for our owners and the communities in which we operate. For nearly two years, we have navigated regulatory uncertainty alongside our customers and other stakeholders as they seek to connect large-load projects to the grid, and meaningful progress has been made. ERCOT has moved the ball forward, and now it is time for PJM to move the ball forward. 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 will 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 are working with them to make that happen. And while we await final clarity, our focus remains firmly on execution. We will 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. We will now open the call for questions.

Operator: Star-11 on your telephone, and wait for your name to be announced. To withdraw your question, please press star-11 again. In the interest of time, we ask that you please limit to one question and one follow-up. Our first question comes from David Arcaro with Morgan Stanley. Your line is open.

Joseph Dominguez: Good morning, David.

David Arcaro: Hey, thanks so much. Good morning. I was wondering if I could get your latest views on the power markets, and maybe ERCOT in particular. I am curious about your interpretation and viewpoint as to the weakness in the forwards even despite some of the very strong data center activity in the pipeline that we are seeing there. What do you make of that, and thoughts on the evolution of that market?

Joseph Dominguez: David, I think the short answer on ERCOT is it is about timing. We have seen that market be all over the place in the last, call it, 90 to 120 days in terms of pricing. The real questions are how much load and when. While there has been a lot of talk about data center and other development activities in ERCOT, it is important to remember that load is not yet on the system—it is getting built. The timing of that will be one driver. And then there is, as you know, an incredibly wide range of forecasted additional potential growth in the ERCOT market, and when that comes in and how it is interconnected remain the questions.

We think ERCOT is undervalued, and we do not think that the prices in the outer years in particular make a great deal of sense. But I will ask a colleague to chime in.

Unknown Speaker: Yes, Joe, I agree with all that. Maybe just to get specific: when Joe says the market is undervalued, we are really focused on the 2028–2029 and beyond period of time. That is really where the load growth can come. There have been over 400,000 MW of large loads in the queue. Obviously, we do not expect anything near that, but the forward market beyond 2029, to us, appears like something that is only expecting 10,000 to 15,000 MW. So if we see numbers like 30,000 MW, we believe that the market will see upward pressure. In the meantime, in the short term, we are not surprised by the weakness, and we have been well hedged and protected against it.

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

Joseph Dominguez: Even that letter, which obviously pertained to regulated utilities and not to entities like Constellation Energy Corporation, referenced the importance of the competitive market. Pennsylvania is very supportive, and 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 discussions that we see now as part of this regulatory proceeding in PJM. Beyond those things, the state continues to be very supportive, under the right circumstances, of 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: Thank you. Our next question comes from Steven Fleishman with Wolfe Research. Your line is open.

Joseph Dominguez: Hi, Steve.

Steven Fleishman: Hi. Good morning. First, on Crane—any updates on the timeline there, and what should we be watching for to suggest that maybe it comes on sooner than the 2031 connection?

Joseph Dominguez: It will come on sooner. What we are talking about is getting full capacity credit for the assets, so I do not want anyone to be under the misconception that the plant will not 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 2027 capacity credit. We are also continuing to work every day with the utilities on speeding up the transmission interconnection process.

Normally, they start off with a pretty long timeline and shorten that up, and we are working with the utilities involved here to shorten up these projects so that we can get on sooner. That is really the update. We will know more when we hear back from FERC. David, do you have anything? I will ask David Dardis if he has anything more on it.

David Dardis: We are hoping to get a response back from FERC in the June–July timeframe. You also saw that PJM acknowledged the importance of the requested waiver without taking any substantive position otherwise. Everything Joe said, I just want to double down on. 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 per the DOE order as an energy-only resource, but we think there is a clear path for FERC to approve the CIR transfer and meet the 2027 deadline.

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

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

Shane Smith: Just to remind folks of the context here, in the consideration for Calpine, we issued 50 million Constellation Energy Corporation shares to the owners—25 million where the lockup expires on 06/30/2026, and the remaining 25 million on 06/30/2027. 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 is really conditional upon what the current owners of the shares want to do. In the nature of being prudent, we will not speak on their behalf around their intent, but we will have the flexibility if there is something that makes sense for both sides.

Operator: Thank you. Our next question comes from Shahriar Pourreza with Wells Fargo. Your line is open.

Joseph Dominguez: Good morning, Shar.

Shahriar Pourreza: Good morning, Joe. Good morning, guys. Maybe 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? Do you need to match new capacity plus existing capacity to get a contract?

Joseph Dominguez: There are two questions there. Nothing is stopping us from moving forward on a deal now, and as I indicated during the last update, we see clients that are interested in doing that, and they figure they will manage whatever comes out of the regulatory process with the tools that they have or other purchases. Other clients want to see what this looks like—what the cost implications are, what our solutions look like, and how our solutions pair up with other things they are looking at in the market—before they move forward. I do not think this is a full stop.

I think it is a pause to see what this looks like and then, hopefully, a quick resumption of those conversations.

Shahriar Pourreza: Got it. And then just as a follow-up, there is obviously a substantial amount of cash to allocate—$5 billion buyback authorized, $8.4 billion of free cash through 2027 and an even higher run rate thereafter. How does that tie into the $0.50 of upside sensitivity? 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? An overall capital allocation update would be great.

Joseph Dominguez: I do not see it as a competition, given our free cash flow capability. We are going to have organic investment opportunities over 10% IRRs. We have talked about a number of those things like the uprates on prior calls. Those things are going to move forward. But we are 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 we think we are going to be able to accomplish, then we are not afraid to buy back our shares. At the end of the day, it is going to be a mixture of all those things. Shane?

Shane Smith: Joe said it well. Shar, what I would say about the $0.50 is we wanted to ensure there was a range or some flexibility in the nature that those investments could take. To the extent you are bringing development online, it obviously has a longer period of time until it becomes accretive, whereas if it is M&A—obviously the case of Calpine—being scale and you are adding $2 per share of EPS a year later. We 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. That could take a number of different shapes and sizes.

The $0.50 was intended to be illustrative based on assumptions you can make on that capital allocation.

Operator: Thank you. Our next question comes from an Analyst with Barclays. Your line is open.

Analyst: Hey, good morning. Thanks for taking the questions and all the updates. I appreciate the free cash flow clarity out to 2029. Could you talk a little bit about the cash conversion between EBITDA and free cash through 2029? 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 think about cash conversion?

Shane Smith: It is not going to change materially from what you have seen with regard to the nature that most of the cash contribution is from the nuclear fleet. If you think about the appropriate assumptions around cash taxes, maintenance CapEx, and how you are accounting for fuel, the conversion will not look significantly different than historical. What I would highlight is, to the extent we are able to execute those levers identified in that conversion between the EPS and free cash flow, a lot of that drops to the bottom line. Those are not requiring incremental investments, and a lot of those are really just a tax adjustment from earnings to cash flow.

Analyst: Thanks for that. And then on the new capacity resources you are highlighting—about 5 GW into the interconnect queue between uprates and natural gas and battery storage—how does that compare to where you were in the March 31 update? You spoke about some idle turbines then. Are you willing to commit to more new build in this plan, and how should we think about the threshold for that?

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

Operator: Thank you. Our next question comes from Julien Dumoulin-Smith with Jefferies. Your line is open.

Joseph Dominguez: Hi, Julian.

Julien Dumoulin-Smith: Hey, good morning, team. Thanks for the time. To follow up a bit on the cadence of things: how do you think about Calvert here versus Limerick or other permutations? Given the evolution of the regulatory dialogues you have had, is there a specific direction? We heard more about Calvert in recent weeks from you all at the Analyst Day. How would you set expectations around that? And then going back to this conversation, is there a specific ratio that you think about in terms of additionality, or how does the curtailment/demand response piece play out into firming up a specific process to move forward on this?

Joseph Dominguez: I am going to give you a bit of a non-answer on which site gets through the finish line first. We mentioned Calvert because, as folks undoubtedly saw later in the day when we did the business outlook, there was a newspaper article on it, and we wanted to share some thoughts before the article came out. Otherwise, we are going to let our customers announce transactions when they are ready, as opposed to doing it here. In terms of how folks are going to manage it and what the ratio of new to existing might be, I think we will see a mix. We talked a little about the Texas deals during our prepared remarks.

That is a good indicator of how wide this range could be—from folks who are completely comfortable using backup generation or other curtailment tools, to sophisticated buyers that already have portfolios of storage, solar, and other resources and want us to manage those toward round-the-clock, 24/7 environmental attributes. The mix will be different for different customers in terms of their ability and willingness to handle curtailment. Data centers themselves are increasingly able to manage some curtailment risk by moving data economy jobs around geographically or in time, shifting non-peak work or moving it to other regions not experiencing stress at that moment. The landscape is changing, and we will see a broad mixture of solution sets.

Any attempt to generically say, “this is the ratio,” would be a fool's errand at this point.

Julien Dumoulin-Smith: Understood. As a quick follow-up: you talked about clarity a lot in the prepared remarks. Is there a specific threshold docket you are looking for to really unlock things? Is there a moment when a document is resolved that could unleash some of this, or, as you suggested, will some customers wait for final deadlines while others proceed earlier?

Joseph Dominguez: I do not want to speak for all customers. For some, the mere filing will be clarity, given where FERC has been. FERC clearly has an appetite for moving quickly. The details of the filing themselves have been helpful already. Some may wait to the end of the backstop proceeding. If they have a colocation idea, it might need to wait for the colocation filings and for FERC's final order on that. The important thing is we are seeing speed here that is unprecedented in my 20+ years with PJM, outside of some expedited RPM changes years ago. We are seeing a commission that wants to solve this.

They understand the importance of getting this right and the importance of the data economy to America. The administration is clearly focused on this, and PJM is acting quickly. I would like to see the colocation implementation date, which PJM had indicated was 2029, moved up, and on that we are aligned with signals from FERC. I expect we will have clarity on all these issues by the end of the year.

Operator: Thank you. Our next question comes from Jeremy Tonet with JPMorgan Securities. Your line is open.

Joseph Dominguez: Good morning.

Jeremy Tonet: Hi. Thanks for all the details today. A high-level question to start: looking at the white paper last week out of PJM—Powering Reliability Through Market Design—were you able to provide any initial reactions to paths A, B, and C? Any high-level thoughts would be welcome.

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

David Dardis: Thanks. We appreciate PJM issuing the white paper and acknowledging the need to revisit its market rules and its commitment to competitive markets for ensuring reliability. A lot of what is in that white paper are things we have talked to PJM about for a number of years, including, in particular, optimizing the energy and reserve markets together and better valuing in the energy market, as opposed to as much reliance as it has had on capacity markets for a number of years. We think that is very positive.

In addition, we have been very supportive—and have been talking for at least two years to anyone who will listen—about bilaterally contracting and firming up supply, given what we saw on the horizon around rising energy prices. We think that is also quite positive. As it relates to option B and differential reliability, that one needs more time to digest and consider potential implications. We certainly agree that flexibility of load is a very important solution going forward. But some sort of permanently discriminatory treatment of different loads around their reliability—allocating reliability on that basis—raises real legal questions that will require more consideration.

If we can start moving more quickly, in particular on energy market reform and co-optimizing reserves, we see that as quite positive.

Joseph Dominguez: And Jeremy, that is something we have urged them to do for a long time, and frankly something that PJM has put on the back burner to its detriment. Two things got us into the pickle we are in. One is capacity prices were too low because we were not considering the actual capacity capabilities of resources adequately. That has changed, and we saw a pop in capacity prices; that should have been managed better all along. The other is that more of the revenue should have been recognized in the energy market, putting less strain on the capacity market, which, as we have learned, can be punitive to residential customers.

It is good to see in this white paper that these issues are back in front of PJM. Competitive market solutions are going to be the right answer. These markets need to enable that quickly. Hopefully PJM follows up with real action on the white paper. They are going to be pressed—the commission is very focused on getting clarity and getting this settled quickly—so PJM has to keep moving this issue forward.

Jeremy Tonet: Got it. That is very helpful. Pricing scarcity is difficult. That is it for me. Thanks.

Operator: Thank you. Our final question comes from an Analyst with Evercore ISI. Your line is open.

Analyst: Hey, guys. Good morning. Just wanted to get a sense on the near-term nuclear uprates—how near term are those, and what is baked into the 2029 assumptions?

Joseph Dominguez: The ones that are in plan are Byron and Braidwood as a general rule. Anything else in the plan right now?

Shane Smith: None of the other uprades. The capital is out the door, but nothing is showing up as EPS accretion in 2029. 2030 is the earliest that they will add to EPS.

Joseph Dominguez: Yes, except for Byron and Braidwood—they are better in plan.

Analyst: Perfect. And then given the strong results in the first quarter—you mentioned they were relatively in line with your expectations—but historically we have seen the biggest question mark around the first quarter. What would you need to see going forward to get more confidence in the upper half of the range, understanding you just spoke a little over a month ago?

Joseph Dominguez: At least another quarter. 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 when we set guidance initially.

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

Joseph Dominguez: Thanks again, everyone, for your interest in Constellation Energy Corporation. We had a good first quarter thanks to our folks. We will continue to strive through the balance of 2026, and we will talk again in about 90 days. Operator, we will 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.