Title

Presentation

Talen Energy Corporation misses on earnings expectations. Reported EPS is $1.33 EPS, expectations were $5.01.

Operator: Ladies and gentlemen, thank you for standing by. Welcome to the Talen Energy Corporation First Quarter Earnings Call. At this time, all participants are in a listen-only mode. After the speakers’ presentation, there will be a question-and-answer session. To ask a question during the session, you will need to press star 11 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star 11 again. Please be advised that today’s conference is being recorded. I would now like to turn the conference over to Sergio Castro, Vice President and Treasurer. Please go ahead.

Sergio Castro: Thank you, Kathy. And welcome to Talen Energy Corporation’s first quarter 2026 conference call. Speaking today are Chief Executive Officer, Mac McFarland, President, Terry L. Nutt, and Chief Financial Officer, Cole Muller. They are joined by other senior executives to address questions during the second part of today’s call as necessary. We issued our earnings release this afternoon, all of which can be found in the Investor Relations section of Talen Energy Corporation’s website, talenenergy.com. Today, we are making some forward-looking statements based on current expectations and assumptions. Actual results could differ due to risk factors and other considerations described in our financial disclosures and other SEC filings.

Today’s discussion also includes references to certain non-GAAP financial measures. We have provided information reconciling our non-GAAP measures to the most directly comparable GAAP measures in our earnings release and the appendix of our presentation. With that, I will now turn the call over to Mac.

Mac McFarland: Great. Thank you, Sergio, and good afternoon, everyone. We appreciate your interest in Talen Energy Corporation, and we look forward to the discussion during our Q&A. I will start with our first quarter results. In the first quarter, we delivered strong operational and financial results, including strong plant performance during the winter cold events, and we are off to a good start to the outage season. In fact, we are in start-up at Susquehanna, slightly exceeding our planned outage duration. Terry and Cole will discuss all of this in more detail later. Also in the first quarter, we signed a Cornerstone transaction advancing our Talen Energy Corporation flywheel strategy and adding meaningful free cash flow per share growth through acquisitions.

Today, we are reaffirming our 2026 guidance and providing a preliminary view of our 2027 and 2028 outlooks. Our 2026 guidance does not include the Cornerstone assets; however, we expect to close as soon as this summer and we will update 2026 guidance once we close. We recently closed on the financing for the Cornerstone acquisition, which positions us to close as quickly as possible once we obtain all regulatory approvals. Cole will explain why we acted now in more detail. In short, the carry cost of funding now should be more than offset by closing as soon as possible. We have also reduced market volatility risk and replaced some higher-cost debt. Our preliminary 2027 and 2028 outlooks do include the Cornerstone assets as well as other updates, including higher current forward mark-to-market values from March 31 of this year, improved financing costs, and several other changes.

These outlooks show significant year-over-year growth in free cash flow per share and meaningful upside versus the outlook we shared this past January. This demonstrates the strength of our business and our continued ability to return cash to shareholders through meaningful share repurchases. These outlooks also imply we are trading at double-digit free cash flow yields, which we do not believe reflect our increasingly contracted portfolio, and that does not include the other levers that we have for further upside, and Cole will walk you through those later. Looking ahead, nothing has changed in our Talen Energy Corporation flywheel strategy. Our direction of travel remains the same. We continue to believe in data center demand for megawatts.

We are building a pipeline of both powered land and new-build options. Terry will walk you through these development activities and how we see the market evolving towards what we call a hybrid model, which uses existing generation for speed to market and is supplemented by new build in later years. Some of you may remember me saying that 2025 was a year of options and 2026 will be a year of market rationalization. While not going into specific project details, we will provide a high-level view of our development portfolio today. We still do expect rationalization across projects in 2026. All that said, we are building a pipeline of real opportunities that can win. With that, I will turn the call over to Terry.

Terry L. Nutt: Thank you, Mac, and good afternoon, everyone. For the first three months of 2026, we are reporting $473 million of adjusted EBITDA and $350 million of adjusted free cash flow. A comparison of these amounts to the same quarter last year provides clear evidence of the accretion Talen Energy Corporation has achieved through acquisitions and fundamental growth in the business. Our fleet achieved strong levels of safety and reliability during the quarter. This is even more noteworthy given the frigid temperatures and icy conditions that were present in late January and early February. We are currently in the middle of our spring outage season across the fleet. Our refueling outage at Susquehanna Unit 1 has progressed well, including executing work similar to what we had on Unit 2 last spring.

The current outage has been more efficient due to the learnings that we had from last year, and it has resulted in the unit being synced back to the grid yesterday. I would like to thank the men and women of Talen Energy Corporation who continue to demonstrate strong operational and safety performance. Without their efforts, none of this is possible. I would also like to welcome the employees from Freedom and Guernsey who were onboarded to Talen Energy Corporation in April and congratulate them on their strong safety records since start-up. Safety remains our top priority across the fleet. Our team worked safely during a busy quarter. Our recordable incident rate was 0.37, which continues to be below industry average. Our fleet ran well and we generated approximately 16 terawatt-hours of electricity, achieving a 55% fleet-wide capacity factor as our intermediate and peaking assets continue the trend of higher run times to support the grid.

We continue to see tightening markets driven by increased demand. In Q1, we saw approximately 3% of incremental deliveries on a weather-adjusted basis in PJM compared to the same period in 2025. This is a clear sign of demand growth that supports our view that energy demand will increase the dispatch of our flexible fleet. Our first quarter generation from 2023 through 2026 increases every year. During this time, our intermediate and peaking assets, in particular Montour and Martins Creek, had significantly higher run times than the same quarter in the prior year, continuing the trend that we have seen the past several years. In relation to spark spreads, we have seen a continued appreciation in the forward curves for the remainder of 2026 through 2028, with the growth in spark spreads across PJM inclusive of the zones where our generation is located.

PPL zone spark spreads have seen appreciation since July, but not as pronounced as the moves in PJM West Hub. We believe that some of this price action that is resulting in widening term basis between West Hub and PPL zone is based on recency bias due to transmission work impacting the zone and not fundamental factors. Our expectation is that this basis will tighten as the transmission network and load evolve. Summer spark spreads continue to move higher driven by fundamentally tight market conditions in PJM. This is even more evident as we have seen increased instances of demand-driven volatility widening cash market spark spreads, which in turn is helping to drive the term sparks higher. This is beginning to validate our earlier views that the market response would come as fundamental drivers are seen in the cash market.

As I mentioned earlier, demand continues to increase with no meaningful increase in supply. This demonstrates the value of steel in the ground. We are working diligently to close the Cornerstone acquisition that we announced earlier this year. It will further diversify Talen Energy Corporation’s generation portfolio and enhance our large load contracting opportunities. As an update on the regulatory approvals, we filed our 203 application with FERC in January and anticipate approval by this summer. The HSR waiting period expired in March, meaning that we have completed the DOJ approval process. And lastly, there was a hearing with the Indiana Utility Regulatory Commission in April and the unopposed final order was submitted. We anticipate approval in Indiana by this summer.

I would like to give you some color on the land development and contracting growth options Mac mentioned earlier. In the near term, we have several 1+ gigawatt opportunities for long-term PPAs at our existing sites as well as other sites in Pennsylvania, and we are advancing potential opportunities across the remainder of our footprint. In relation to specific site development opportunities for land we are currently working on, we are progressing on several different fronts. Those opportunities include land of up to 3 thousand acres in total that can support 3 to 4 gigawatts of data center capacity using current compute density. The zoning of the property ranges from fully zoned acreage to zoning activity that is still in process, such as our Montour site.

Additionally, we have the ability at several of these sites to install new generation of 500 megawatts to 1 gigawatt. As part of our strategy, we are advancing a mix of gas and storage generation projects totaling over 2 gigawatts at our sites to support data center contracting and reliability needs. Last week, we submitted several new projects into PJM’s Cycle 1 interconnection study cluster. These projects are a mix of generation solutions including CTs, batteries, and CCGTs. These new generation sources, in combination with our existing assets, provide us the ability to offer a solution to customers that is a hybrid approach of receiving power from existing generation now and new generation down the road. As we have stated before and will reiterate today, development of new generation will need to be done either through long-term offtake agreements or through the PJM RVP, with a focus on financial discipline related to investment return.

This initial generation development is capital-light with no material capital required during the initial stage. As development advances, spending will be tied to customer contracts and underwriting, and we will likely utilize project financing structures related to these projects. With that, let me turn it over to Cole to cover our financial results.

Cole Muller: Thanks, Terry, and good afternoon, everyone. Looking at our financial results for the first quarter, we reported $473 million of adjusted EBITDA and $350 million of adjusted free cash flow. Adjusted EBITDA more than doubled and adjusted free cash flow quadrupled year-over-year, showing the impact of the Freedom and Guernsey acquisitions that we closed in Q4 last year. These results were also driven by higher prices and spark spreads, higher capacity and ROR revenues that started in June 2025, and the ongoing AWS PPA ramp. Our adjusted free cash flow also benefited from reduced cash tax payments largely related to the impacts from our Freedom and Guernsey acquisitions. We are reaffirming the previously announced 2026 guidance ranges.

We had a strong first quarter, though it is not our practice to make adjustments this early in the year. Our adjusted EBITDA range is $1.75 billion to $2.05 billion and our adjusted free cash flow range is $980 million to $1.18 billion. These ranges do not include any contribution from the pending Cornerstone acquisition. We expect to provide an update to 2026 guidance after closing the transaction. We remain committed to maintaining sufficient liquidity and keeping our long-term net leverage ratio below our stated target of 3.5x. As of March 31, our forecasted 2026 net leverage ratio was 3.1x. I will note this excludes any impacts from the Cornerstone acquisition and the associated debt that we raised back in April. Upon closing the Cornerstone transaction, we expect to maintain the ability to achieve below 3.5x net leverage by year-end 2026.

We recently secured attractive acquisition financing for the Cornerstone assets, which also provided us an opportunity to optimize the balance sheet. We raised $4 billion of senior unsecured notes in a private placement across five- and seven-year tranches at a blended rate just above 6.25%, de-risking the Cornerstone acquisition financing at attractive pricing and allowing us to be ready to close upon regulatory approvals. We also took out our $1.2 billion senior secured notes that had an 8.625% coupon, delivering more than $40 million per year in interest expense reduction, which adds nearly $1 to our free cash flow per share. I will spend a moment to give more color on why we made the decision to raise the financing ahead of regulatory approvals.

First, doing this now, we avoided potential risks to market availability, such as impacts from geopolitical events and upcoming midterm elections, as well as locked in attractive long-term rates in the process. We also removed any complications if we needed to raise funds while potentially in possession of MNPI in future months. Second, having the financing already in place ahead of regulatory approvals speeds up time to close, meaning we can own the asset sooner and benefit more from the peak summer period. We estimate the value of one additional month at approximately $30 million in additional cash flow, which far outweighs the net negative carry of only a few million dollars a month. Note that a portion of the proceeds allowed us to take out the more expensive senior secured notes last week and immediately realize interest savings.

Considering where things stand with the regulatory approval processes, we feel that this was the right time to lock down the financing. In eliminating the senior secured notes, we have materially reduced our secured debt composition from approximately 60% of total debt down to 30%, leading to improved credit ratings across multiple agencies. Concurrent with this financing, we are enhancing our liquidity through commitments to upsize our existing revolving credit facility to $1.35 billion and our standalone letter of credit facility to $1.5 billion. We are also extending the LCF maturity through December 2029. These credit facility changes go into effect upon closing the Cornerstone transaction. We show a preliminary update to our 2027 and 2028 outlook that includes the Cornerstone assets along with impacts across the business since last September’s Investor Day, including spark spread expansion through March 31 and impacts from the recent financing that I walked through a moment ago.

We also separately include the expected impacts of executing on our share repurchase program, assuming we utilize 70% of available free cash flow. In our base case, we hold share count flat, projecting free cash flow at approximately $34 per share in 2027 and approximately $36 per share in 2028, a 15% improvement from our January estimates, which included the Cornerstone acquisition. When factoring in our share repurchase program, we project approximately $41 per share in 2028, a 30% increase to what we showed back in January. At these projected levels, our free cash flow yield is about 11%. Note that this assumes we use 70% of free cash flow, leaving approximately $1 billion of additional cash available across 2027 and 2028 as more upside for shareholders.

In addition, we continue to see upside through the flywheel with accretive M&A—which we demonstrated with the Freedom and Guernsey and now Cornerstone acquisitions—and also through acceleration of the Amazon ramp established in our existing PPA, new data center contracting opportunities, and further spark spread expansion as markets continue to tighten. In fact, we have already seen significant improvements in spark spreads since the March 31 pricing date of approximately $5 per megawatt-hour beyond what is shown in these numbers, which translates to several more dollars per share if marked today. We also expect the recent widening of the West Hub to PPL zonal basis to revert to more recent average levels. Note that in our outlook here, we include the most visible mark that reflects this elevated zonal basis, though as Terry mentioned earlier, we do not see this recent shift being fundamentally driven.

A $5 per megawatt-hour impact across 30+ terawatt-hours in PPL zone presents a compelling upside opportunity, particularly as load growth occurs within the zone. Each of these opportunities could provide 10%+ in additional free cash flow per share growth beyond what is shown here, offering a compelling set of further growth opportunities. I should note that there may also be additional upside in 2026 that is not reflected here based on closing the Cornerstone acquisition this summer and/or executing on our share repurchase program throughout the remainder of the year. I want to emphasize that we will continue to maintain capital discipline with a clear focus on accretive levers that meaningfully increase free cash flow per share available to investors through the Talen Energy Corporation flywheel.

We show the overall contracted profile of our business when our existing nearly 2 gigawatt PPA reaches full ramp inclusive of the megawatts and cash flows from the Cornerstone assets. With 35% of our gross margin contracted in the long term, contracted cash flows with the AA credit counterparty will be our largest revenue stream, de-risking long-term exposure to PJM capacity and energy markets. In addition, for every incremental 1 gigawatt PPA that we secure, our long-term contracted gross margin increases by 15%, meaning that our next 1 gigawatt PPA may increase our long-term contracted gross margin to 50%. We believe this is a differentiated position with growing cash flows that are becoming more durable. I will now turn it back to Mac.

Mac McFarland: All right. Thanks for joining us. That is our prepared remarks. I will now turn it back to the operator and open the line for questions.

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Operator: Thank you. At this time, we will conduct a question-and-answer session. As a reminder, to ask a question, you will need to press star 11 on your telephone and wait for your name to be announced. To withdraw your question, please press star 11 again. Please limit yourself to one question and one follow-up. Please stand by while we compile our Q&A roster. Your first question comes from the line of Shahriar Pourreza with Wells Fargo. Your line is now open.

Shahriar Pourreza: Hi, good afternoon team. It is actually Constantine here for Shar. Congrats on a great quarter and the development updates. Maybe just starting off on the PJM backdrop with the site development for data centers. Is there tentative framework on things like new capacity versus existing capacity matching, like a one-to-one ratio? Or how flexible would you anticipate that to be going forward, especially as the reserve auction is trying to kind of back-solve this capacity issue?

Cole Muller: Yes. Thanks, Constantine. As we have talked about previously, we continue to believe there is opportunity to contract off of our existing generation. Obviously, generation is an important component in how to incentivize a lot of new resources. It is a topic for a lot of discussion right now. As Terry mentioned in the remarks, we do see bringing new generation on the back of PPAs with existing generation. The hybrid model that we have been talking about and working on will help incentivize both contracting near term as load grows over the next three to five years but also bring new generation in the 2030 and beyond timeframe. Certainly not in a one-for-one manner, but we do think a percentage—as you have seen in some other deals over the last number of months—of new build will be part of the solution.

Mac McFarland: And to follow up on what Cole said, we have a reserve adequacy issue that has been identified. As we have said for a number of years now, that is really a fifty-hour problem. We are looking at opportunities to solve that. It does not necessarily need to be one-to-one for baseload generation because there are plenty of hours where there is ample energy available. What solves those fifty hours? That is why we have a mix of both batteries—which are the next quickest to market—CTs as the most cost-effective thereafter, and CCGTs for the long run. We are looking at it all in the construct, but we do not think a 1 thousand megawatt PPA requires 1 thousand megawatts of additionality. You can solve that with a number of things to increase the reserve margin for that load.

Shahriar Pourreza: Okay. So just to ask a little bit differently, it does not have to be a CCGT-based solution for some of the site development that you are looking for, right?

Mac McFarland: No. We actually think that if you look at what is likely to happen in the RVP, you are going to see upgrades. You are going to see CTs converted to CCGTs, which is effectively an upgrade of an existing machine. You are going to see batteries and peakers be the least-cost solution. In our broad-based coalition that we put forth for the RVP, we support a pay-as-bid construct to drive home the affordability issue that is out there. We think that is the least-cost way to do that. CCGTs happen to be at the steeper end of that cost curve, and we think there are more effective ways to solve the reserve margin need.

Terry L. Nutt: And to add to Mac’s comments, when you take a look at our existing fleet-wide capacity factor, outside of those fifty hours a year where you have real capacity needs, you can see that there is excess generation on the grid that can support more megawatts outside of those peak periods. If you go back to the slide that we presented, you see this slow, steady creep up in demand, yet there is still excess capacity. That is the reason why you do not need a one-for-one construct in the grand scheme of things. We are solving for the peak hours of the day in very tight periods of time, which, as Mac said, is a capacity issue, not an overall energy issue.

Shahriar Pourreza: Maybe quickly following up on the regulatory issue here: with the PJM colocation rules progressing at FERC, how comfortable are your customers in terms of progressing with some of the data center development and the site development while rules are still being finalized? Is there any threshold to look out for?

Cole Muller: I would not say there are thresholds. There is a lot of dialogue about where things are going. You mentioned the colocation docket, there is obviously the RVP, and there are other related matters that PJM and others are talking through. We still see significant interest in connecting to the grid and taking power as soon as possible, and that is going to be done off of existing generation. We think that hyperscalers and others will understand that they need to incentivize and bring new generation in five-plus years, but there is no specific threshold they are working towards.

Terry L. Nutt: To add a bit more color, the existing development and construction that we see at data center sites across Pennsylvania, using the site near our Susquehanna facility as a great example, is continuing at a steady pace. They are moving forward, getting data halls filled, getting things electrified. We do not see a slowdown in that at all. The hyperscalers’ earnings calls last week showed the continued trend in their businesses. The revenue streams are there, they are moving forward fast, and the capital is hitting the ground in tangible infrastructure.

Operator: Your next question comes from the line of Rinny Raveena Singh with Bank of America. Your line is now open.

Rinny Raveena Singh: Hi, guys. I just had a question first on the power prices. I know you said that PPL is trading a little bit different than PJM West just because of recency bias. When do you think we might see a correction in that? And is there a specific catalyst to watch for?

Terry L. Nutt: Let me start on this one, and then I will hand it over to Chris, who is with us here today. There has been a lot of transmission work in and around PPL zone and other parts of PJM that has been worked on over the last several months. There is a lot of temporal, short-term congestion that we are seeing across the board. Our view, as mentioned in the prepared remarks, is that as load evolves and pops up in PPL zone and other load pockets, we think that basis would trend back and come in line. Chris, do you want to add anything?

Christopher E. Morice: Yes. The auction process itself has some illiquidity and timing issues, and reflected in those marks is how those auctions clear. Those disconnect from some of the projections that we are making. Near-term acuteness in basis as a result of this ongoing transmission work is bleeding into that term price. Picking a time in which that reverts or comes back to something more normal will happen through time as that load appears, not as a binary instantaneous moment in time.

Cole Muller: We use the most visible marks out there, and we use the PPL zone mark. In the appendix, we show the West Hub–PPL basis over time. For multiple years it traded very narrowly in a range. That has broken out over the last couple of months for the reasons Terry and Chris noted. From a market perspective, we stay true to what is visible, which is why we are calling it an upside opportunity.

Mac McFarland: And just one further follow-on: while the basis has widened, the entire market is up. The term market is starting to rationalize supply-demand. While the basis widened, marks were up versus March 31, and even further if you went to yesterday. We think the basis issue is temporal.

Rinny Raveena Singh: On the load growth and new build, how are you thinking about new prices for CT or CCGT? And how do you manage the risk of the RVP to fill in capacity price, and the energy risk—focus on long-term data center contracts at higher prices?

Terry L. Nutt: You have seen a significant amount of appreciation in the turnkey cost for a CCGT and similarly for combustion turbines. In our proposal for the RVP—and consistent with what PJM has discussed—we think it should be a capacity product. If you build a CT on the back of a reliability backstop award, the capacity revenue stream should underwrite or incentivize that. Energy and ancillaries are second tier. The ability to get that award for multiple years—PJM has talked about up to 15 years—is key. The biggest challenge is not getting additional resources, it is financing those resources and the underpinnings to underwrite and finance them. We think PJM’s proposal largely hits the mark, with some modifications we would like to see.

Operator: Your next question comes from the line of Analyst with BNP Paribas. Your line is now open.

Analyst: Thanks for taking my question. On the change in free cash flow per share to 2028—last quarter you showed $31–$40 including Cornerstone, now it moves to $41+. You are not leaning on upside drivers like M&A and PPAs in there. How much of that roughly $10 increase is driven by spark spread expansion versus balance sheet and other factors? And any assumption embedded of higher capacity factors on the fleet?

Cole Muller: We are not going to get too specific on all the different drivers line by line, but it is all in there. We showed the impact of the share repurchase program separately. The other levers—Cornerstone numbers and spark spreads, among others—get you to a directional answer, but we are not breaking it down further.

Analyst: On the backstop option broadly, is there a view of if they will even clear 15 gigawatts—batteries, CTs, some CCGTs—by 2031 with queue reform? Do you think some goes into the second stage of the clearing process, or would the bilateral process do most of the heavy lifting?

Terry L. Nutt: When you take a look at cost and affordability, there are some obvious choices on technology. PJM’s cost of new entry benchmark is a CT, which is the most affordable. Certain CTs and batteries can be built more quickly, which matters for reliability backstop timing. CCGTs have longer turbine lead times. The interconnection queue needs clearing and prioritization—that is one area where we are actively engaged in the stakeholder process. Ultimately, the queue matters quite a bit to get new resources online. It is good progress—we will see it push forward.

Operator: Your next question comes from the line of Michael P. Sullivan with Wolfe. Your line is now open.

Michael P. Sullivan: Why not lean into the development sites that are already fully zoned versus ones getting more public pushback? On the fully zoned ones, what is the hang-up?

Terry L. Nutt: On that slide we wanted to give a flavor of the team’s work across the board for well over a year. The ones you hear about publicly—like Montour—we continue to progress, but we have others not in the press that we are pushing forward as well. We wanted investors to understand the broader context. As we think about the hybrid approach—finding some new generation to add—we think that solution checks a lot of boxes for hyperscalers. It is not just zoning; it is also whether you have some new gen to go with it and what existing gen you have on the back of it.

Mac McFarland: I do not think there is a hang-up. We are developing a set of options and they all have different statuses as they move through the process. Sometimes one site that has not reached zoning might advance faster because it is preferred by a counterparty at that stage. Others are more zoned and come in. We are bringing along all of these options; Montour is not the only thing in our development pipeline.

Michael P. Sullivan: On pricing action, things have moved a lot in the last couple weeks in a shoulder season. What is driving that? And on basis, it seems like it is still going the wrong direction.

Terry L. Nutt: One of the things you are seeing is when cash market activity in real-time gets constrained and tight, the term market responds. In late January and early February, there was a significant pricing event for eight or nine days. The market reacted. More recently, during spring outages—when you have a traditional large set of outages—even modest weather can drive price volatility and cash pickup, and the term market feeds off that.

Christopher E. Morice: The price appreciation is something we have been tracking and identifying for several quarters. We would highlight our current hedge percentages in the outer years—below our historical ranges—reflecting our conviction in those periods. Fundamental drivers in the cash market are manifesting through the curve over time.

Operator: Your next question comes from the line of Agnieszka Storozynski with Seaport. Your line is now open.

Agnieszka Storozynski: I wanted to talk about Ohio. You have owned Guernsey for quite some time, and there has been chatter around data centers in Ohio. We heard comments from AEP about dissatisfaction with load interconnection pace in PJM. We also saw behind-the-meter deals. You showed opportunities in Pennsylvania. Could you comment about Ohio, especially vis-à-vis Guernsey?

Terry L. Nutt: We noted specific activity in Pennsylvania, but we have also been active in Ohio. We have talked to customers in and around the Guernsey site and across the broader state. We restructured the leadership team at the end of last year and put more focus on different parts of the market—Ohio is definitely one of them. It is a very established market in and around Columbus with several hubs, and we are pushing there as we are in Pennsylvania.

Mac McFarland: We like Ohio. We have amassed over 4 gigawatts of gas fleet across there, including a plant in Indiana that serves Ohio. We did that for a reason. The fundamentals and price appreciation are attractive, and it does not have a negative West Hub basis. We are developing options in Ohio, as we are in Pennsylvania, but we are not going to get into specifics.

Agnieszka Storozynski: On slide 12 and the Talen Energy Corporation flywheel, it was my understanding that after M&A the next step is monetization of assets. You show M&A as the first upside driver. Is it fair to assume we would first see monetization before another M&A transaction?

Mac McFarland: There is nothing to the order of the items on the right-hand side; we kept consistency with prior presentations. In a perfect world, you would add assets, contract them, recycle capital, then add assets again. In reality, we make strategic actions consistent with the flywheel that can be lumpy. We are diligently working to increase our contracted energy margin—toward 50%—and looking at different opportunities. These things take time, and we feel like we have a good pipeline to get things done.

Operator: Your next question comes from the line of William Appicelli with UBS. Your line is now open.

William Appicelli: On the levelized cost of energy for new build, how wide is that spread—even for a CT—relative to current market conditions?

Cole Muller: The gap is wide on a merchant basis for any new build. That is why we—and many others—will do new build supported by some kind of commitment, whether a bilateral contract with a hyperscaler or through the RVP and PJM. That gap has to be bridged for us to make a large commitment in an accretive manner. Current capacity clears are not sufficient to stimulate new build. Different technologies have different LCOE; combined cycles are most expensive but have more energy margin—tradeoffs. The gap is not a couple of bucks; it is pretty large.

William Appicelli: Any concerns about a bifurcated market where new incremental megawatts are getting sufficient payment but existing generation is not?

Mac McFarland: It is a concern raised broadly, but we do not share the same level of concern because we supported the RVP as a one-time action. The capacity cap was extended for 2029/2030 and 2030/2031—we supported that. It gives time to create and exercise the RVP. It is a valid topic, but we are comfortable with the path.

William Appicelli: Lastly, on new gen options, would that include any repowerings or uprates of your existing assets?

Terry L. Nutt: It does not.

Operator: Your next question comes from the line of Julien Dumoulin-Smith with Jefferies. Your line is now open.

Julien Dumoulin-Smith: Coming back to the ratepayer protection pledge from March—does that change anything about your approach to the RVP or strategy?

Mac McFarland: The hyperscalers’ pledge to pay their fair share is noted, but there is still an open debate about what “fair share” is and how it is determined within PJM’s market constructs and jurisdictions across PJM, the states, and FERC. Implementation is working its way through. We still see the ability—because of speed to market—to contract through existing assets and to utilize the hybrid model to bring incremental generation for additionality and ratepayer protection. It will take time to evolve. Hyperscalers have not signed up to pay for everything—that is not how restructured markets work.

Julien Dumoulin-Smith: As you talk about 500 megawatts to 1 gigawatt of new gen per site, are you thinking about tethering that new gen back to the one-plus gigawatt site opportunities?

Mac McFarland: Yes, that is the concept in the hybrid model. We have multiple sites with 500 megawatts to 1 gigawatt potential each, and we recently submitted just over 2 gigawatts into PJM’s cluster. Tethered means pairing existing PPA-supported generation with new resources—batteries or CTs to solve the fifty-hour adequacy problem now, and CCGTs later when you need more energy coverage. You can put those on the back of existing PPAs and solve resource adequacy at a lower cost than immediately building CCGTs, which today can be $3 thousand to $4 thousand per kilowatt to build—far more than $500 per megawatt-day capacity revenues would cover.

Julien Dumoulin-Smith: To bring it to conclusion, would an RVP award be the moment that could unlock contracting? Or a bilateral could come first?

Terry L. Nutt: There are two paths: a direct offtake agreement with a hyperscaler or an RVP award. It will depend on which path comes first; both can support bringing new megawatts online.

Operator: Your next question comes from the line of Nicholas Amicucci with Evercore. Your line is now open.

Nicholas Amicucci: Happy Cinco de Mayo. A quick follow-up on Julian’s question: is it fair to say the new generation could be supported either by a long-term DC offtake agreement or the RVP? How do you frame capital deployment—Is RVP more of a fallback, or are economics competitive with a hyperscaler PPA?

Mac McFarland: It is not a discrete choice between the two. We will participate in the RVP and in bilateral markets via the hybrid model. The RVP is a centralized, one-time backstop to address resource adequacy, while there is a parallel bilateral market to bring additionality. Bidders will have to decide their capacity and energy bids. CCGTs require a bigger capacity component and energy margin expectation, but we think there are least-cost solutions—batteries and CTs—that can come in under those costs.

Nicholas Amicucci: On buybacks, you referenced a double-digit free cash flow yield. You did $100 million in Q1, with $1.9 billion remaining through 2028. Should we expect any acceleration to the Q1 pace, particularly as Cornerstone closes and leverage trends below target?

Mac McFarland: When we have the opportunity and can exercise, we like to get in and buy the shares back. $100 million is part of the $2 billion allocation, and we plan to continue at scale over time.

Cole Muller: Slide 12 breaks out the share repurchase impacts. To get there, we will be doing things at scale over time. We are committed.

Operator: Our final question comes from the line of David Keith Arcaro with Morgan Stanley. Your line is now open.

David Keith Arcaro: Could you give any color on what you are hearing from potential counterparties? Are they waiting for more clarity on the backstop procurement? Are there milestones—final PJM rules or running the procurement—that would accelerate contracting?

Terry L. Nutt: It is a balance. There is pretty good consensus now on the reliability backstop; we are talking about details. Stakeholders, including customers, have gotten comfortable with that. Some discussions have moved more to the hybrid approach—bringing new generation and adding that to the solution mix. We do not think anything is hindering folks from transacting. Would they prefer 100% clarity? Yes. But they also have demand they need to meet for their customer base, so it is a little of both.

Mac McFarland: We have been providing comments on the RVP, including not making it such an extended program. In stakeholder sessions over the last couple of days, PJM started to reformulate timing to be this fall, which we think is good. Anything that brings clarity helps. But capital plans at the hyperscalers are not slowing down. Clarity helps, but it is not necessary. Unfortunately, we are going to have to end it there. I do see that there are a couple more questions in the queue. Apologies to everybody we did not get to—we have run out of time. We appreciate you joining us today and your continued support of Talen Energy Corporation. In summary, we have a strong 2027–2028 outlook with multiple levers we can pull and further upside from spark spread expansion.

We are also hopefully pulling back the curtain a bit to show that we are set up to execute on growth through our development pipeline and the opportunities we have been working on for some time. We are excited about that. We look forward to powering the future. Have a great day.

Operator: Thank you for your participation in today’s conference. This does conclude the program. You may disconnect.

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