Talen Energy Corp Q2 FY2024 Earnings Call

Ladies and gentlemen, thank you for standing by. Welcome to Talen Energy Corporation’s Second Quarter 2024 Earnings Call. At this time, all participants are in a listen-only mode. After the speaker’s presentation, there will be a question-and-answer session. Operator Instructions: Please be advised that today’s conference is being recorded. I would like now to turn the conference over to Ellen Liu, Senior Director, Investor Relations. Please go ahead.

Thanks, Michelle. Welcome to Talen Energy’s second quarter 2024 conference call. Participating on today’s call are Chief Executive Officer, Mac McFarland; and Chief Financial Officer, Terry Nutt. They are joined by other Talen senior executives to address questions during the second part of today’s call as necessary. We issued our earnings release this morning along with the presentation, all of which can be found in the Investor Relations section of Talen’s website, www.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.

Great. Thank you, Ellen. Good morning, everyone, and thank you for joining us. Before we get into our earnings results and presentation, I’d like to comment on the challenges and opportunities facing our industry as we meet the growing electrification needs of the AI economy. At Talen, we have come up with one creative cost-effective solution by co-locating a 1-gigawatt AWS data center campus next to our Susquehanna nuclear plant. Everyone seems interested in our efforts, our colleagues in the IPP space, regulated utilities and RTOs. And the issue now sits at FERC’s doorstep, where it plans to hold a technical conference on the broader issues this fall. In the investment community, our deal created excitement about increased demand and incremental value creation across the entire power sector, attracting new investors. And I’ll admit it is one of the most exciting times I’ve seen in my power career. It will drive unprecedented change in our industry, change that will yield great opportunity. The focus has now turned to the question how will the value creation get shared across companies? The recent high PJM capacity auction prices coupled with this new demand have caused people to discuss the repeal of deregulation, RTOs coming apart, states separating from PJM, and to engage in other comments and distracting discussions. These ideas are misguided and miss the point that PJM has been a highly successful, competitive market, keeping prices relatively low and providing reliable electricity and bringing to market nearly 60 gigawatts of new build capacity in the past two decades. This rhetoric creates uncertainty, which, if allowed to persist, chills investment and job creation at a moment in time when we all have an exciting new demand to serve. They also miss the point that the opportunity here is so large that regulated companies, T&D companies and generators will all participate in the value creation, and in fact are all necessary for the solution. I typically agree with the saying, where you stand depends on where you sit. However, I think at this time, we all sit in the same place. As I see it, it is a win-win for everyone if we can get it right. The IPPs, T&Ds, as well as the customers in the region we serve who will benefit from increased reliability, lower cost and much-needed economic development. This is an opportunity for us as an industry to lead. Everyone’s talking about 15 gigawatts of backlog here, 5 gigawatts of backlog there and so on with respect to data centers. While these estimates seem large, the customer need is really large, and a matter of when, and to some extent where, but not if. How will we as an industry rise to the occasion to meet the challenge of electrifying the future? You’ve heard me discuss it before. The big four hyperscalers have a 2024 CapEx budget of nearly $250 billion and those estimates have been rising. And they’re on a pace to spend over a $1 trillion by 2028. And you can reach a similar conclusion if you look at chipmaker production forecasts. Electrifying that growth in data center demand will challenge the industry to deploy capital for new generation and transmission enhancements in the billions of dollars for every gigawatt of data center capacity when the existing capacity on the grid is insufficient. The generators cannot do it alone and the T&Ds cannot do it alone. One forecast of data center growth totals 60 gigawatts of capacity by the end of this decade nationally, with nearly 15 gigawatts of that being in PJM. That means we as an industry will need to deploy hundreds of billions of dollars to meet this need. This will mean an opportunity for generation developers and significant rate-based growth for T&D companies alike. If we can bring these solutions to the customers and meet the needs of the AI economy, we can help drive economic development for the states we operate in. For every gigawatt of data centers built, direct investment is roughly $10 billion and the total economic impact is a multiple of 2 times to 3 times that when you add the ancillary jobs and investment created. So we really should think about this as a $20 billion to $30 billion of economic development for every gigawatt of data center investment. This is a big economic opportunity for those who get it right, housing, schools, services, jobs. It’s no wonder the labor leaders I talk to are highly supportive and I am optimistic we can get it right. Turning to our specific deal with AWS, when we announced our deal, we did not kid ourselves. We knew we had a solution, one that was quick to market, cost-effective and reliable. But we also recognized that it is not the only solution. Our behind-the-meter Direct Connect Solution is just one innovative way to solve one gigawatt of the challenge. Many others will have to follow, and the next evolution will need to be balanced. Balanced in its form of supply for customers, behind-the-meter, front-of-the-meter and whatever creative solution can be developed. Balanced in terms of the appropriate cost sharing, protecting residential rates and maintaining grid reliability. Our one deal brings hundreds of jobs and tens of billions of dollars of economic development to the state of Pennsylvania, and importantly for us, the Greater Berwick area. Our one deal matters because data centers form in multi-site clusters. So we hope that proving one working model in Pennsylvania is a sign of good things to come for further build-out. While our ISA has been the subject of much debate, we remain optimistic that FERC will approve the filed amendments once PJM responds to FERC’s question and the commission has had time to fully review. We look forward to participating in the technical conference this fall, and I am confident that as an industry, we can meet the challenges in front of us, seize the opportunity to power the AI economy and do it swiftly so that we can bring about the economic benefits and investment capital to PJM, Pennsylvania, and the entire U.S. I’d like to quickly mention our RMR proceedings at Brandon and Wagner. After the recent PJM capacity auction results, people have asked us if we’re going to change course from the RMR process. Said simply, no. That’s not how it works, and it’s more complicated than that. So as long as we are paid a fair rate, we are committed to the RMR process and are working with stakeholders in settlement discussions before FERC to try to reach an agreed-upon rate that will allow us to stay online. That said, we are willing to consider repowering the site and potentially adding batteries under the right circumstances. This could make sense and could potentially eliminate costly transmission upgrades. We look forward to continuing the process and finding a solution, as I said, with all stakeholders. I look forward to your questions on these important matters and will now turn to our key highlights for this earnings call. So starting with Slide 3, Talen has had an active second quarter. I’d like to highlight several of our achievements. One overarching theme is the increasingly visible impact of rising power demand through higher prices in both energy and capacity markets. In the second quarter, our fleet ran well during periods of unusually high temperatures and demand in PJM, enabling us to capture healthy generation margin. As our gas fleet ran significantly more than it did in Q2 of last year, demonstrating the value of dispatchable generation in a rising power market. Given our solid first half performance, we are raising our 2024 adjusted EBITDA and adjusted free cash flow guidance ranges and the representative midpoints. With respect to the recent PJM auction, our fleet cleared 6.8 gigawatts of capacity at roughly $270 per megawatt day in the 2025-2026 auction, compared to $50 per megawatt day in the prior planning year. This equals $600 million in capacity revenues for the 2025-2026 planning year. AWS continues to make progress on its data center campus near Susquehanna. The local township recently granted AWS a zoning amendment that will allow the construction and operation of 960 megawatts of data centers, and in Q3, we expect to receive the $300 million of sale proceeds currently in escrow. Additionally, we reached another strategic milestone by listing on the NASDAQ exchange on July 10th, which in turn improved the trading liquidity of our equity, enabled greater access for more investors and made us eligible for major indices. We are proud of the value that we have unlocked and believe there’s more opportunities for value creation to come, especially in the current market backdrop. So please join us at our Investor Day in Newark on September 5th. I’ll now turn the call over to Terry for further details.

Thank you, Mac, and good morning, everyone. Moving to Slide 4, let’s take a look at our year-to-date operational and financial results. Our fleet ran well during the period, generating over 16 terawatt hours of power, with an equivalent forced outage factor of only 2%. Fifty-three percent of that generation came from our carbon-free Susquehanna nuclear facility, which successfully completed spring refueling outage in April. Importantly, our whole team worked safely, with year-to-date total reportable incident rate of only 0.3. This is in line with or better than our peers, and we continue to emphasize safety as our first priority across the fleet. We leveraged our strong operational foundation and commercial strategy to earn $376 million of adjusted EBITDA and $165 million of adjusted free cash flow year-to-date. We continue to prioritize capital returns and balance sheet discipline. Our net leverage is only 2.4 times, far below our 3.5 times target and we currently have over $1.1 billion of liquidity, thanks to cash generated from operations. This gives us capital allocation flexibility and enables us to focus on shareholder returns. I’d like to take this opportunity to recognize and thank our employees across the company, who have worked safely to deliver impressive operational results. The past couple of months were the busiest time of year for many of our operations team members, as they successfully navigated our spring outage schedule across the fleet. These team members are key to our overall performance as they operate, maintain and improve our generation fleet and other assets. Without their hard work and commitment to excellence, none of this would be possible. Turning now to the PJM capacity auction results on Slide 5. As Mac mentioned earlier, the 2025-2026 auction cleared at significantly higher prices than prior years, with PJM’s reserve margin declining from 20% to 18.5%. Focusing on calendar year impacts, Talen will earn roughly $285 million more in capacity revenues in 2025 when compared to 2024. These results illustrate how Talen is the IPP most levered to PJM’s capacity auction outcomes. These auction results are a strong indication of a tightening market, but I will caution that it’s currently just one data point. The results also demonstrate the value proposition for reliable, dispatchable generation. Looking ahead to the next auction, we expect supply tightness to persist. Years of low energy margins and capacity prices led to a large exit of reliable legacy generation assets, and investment signals need to be persistent to spur long-term investments and new dispatchable resources that have 30-year investment horizons. Furthermore, the supply chain for turbines, transformers and other equipment in the global market presents challenges, meaning that building and bringing a new gas-fired plant online could take five years or longer. PJM’s parameters for the 2026-2027 capacity auction will be available in late August and the auction will be held in December, while the following planning year auction will be in June of 2025. Now turning to financial results. For the second quarter of 2024, Talen reported adjusted EBITDA of $87 million and an adjusted free cash flow use of $29 million. Building on our solid financial performance in the first quarter resulted in $376 million of adjusted EBITDA and $165 million of adjusted free cash flow year-to-date. As a reminder, our business is seasonal and we make most of our money during the core winter and summer months. The second quarter and fourth quarter are shoulder periods when we typically don’t earn as much and often schedule our maintenance hours. Additionally, certain periodic cash payments happen in the second and fourth quarter. That further reduced cash flow, such as our semi-annual debt service payments. That said, the second quarter was strong for Talen. In PJM, second quarter weather was unseasonably warm, with Philadelphia experiencing its highest average cooling degree day total since 2014. Additionally, this quarter’s average power demand in PJM was the highest second quarter demand seen in the last five years. In this market backdrop, our PJM gas fleet demonstrated the value of dispatchable generation, producing approximately 1.5 more terawatt hours and $20 million more of generation margin than the same quarter of 2023. Turning now to guidance on Slide 7. Based on our solid first half performance, we are raising our 2024 adjusted EBITDA and adjusted free cash flow ranges. Our new adjusted EBITDA range is $720 million to $780 million, with a midpoint that is 7% higher than prior guidance. And our new adjusted free cash flow range is $245 million to $285 million, with a midpoint 13% higher than before. I’d also like to take a moment to highlight our hedging activity from this past quarter. On Slide 8, there is a graph of average calendar year 2025 and 2026 spark spreads. Spark spreads expanded considerably through mid-April before retracing by the end of June. During this period, our commercial team successfully executed our hedging strategy and added hedges when spark spreads were higher, as detailed on the right-hand side of the slide. Turning to Slide 9. We remain committed to maintaining net leverage below our 3.5 times target, along with ample liquidity. As of August 9th, our forecasted net debt-to-EBITDA ratio was only 2.4 times, well below our target. We continue to actively engage with the rating agencies and currently maintain positive outlooks with both S&P and Moody’s. In addition, we have over $1.1 billion of liquidity, including over $400 million of unrestricted cash. We’ve taken several actions since the end of the first quarter to optimize liquidity, including remarketing our municipal bonds, which allowed us to terminate $133 million of letters of credit that were backstopping them. We also terminated over $90 million of other letters of credit, opening up even more capacity under our credit facilities. Moving to Slide 10. Since the start of 2024, we have returned approximately $930 million to shareholders by repurchasing roughly 8 million shares or 14% of our shares outstanding. We’ve executed most of these buybacks through two large transactions. In June, we repurchased approximately 5.3 million shares through a $612 million tender offer. And in July, we bought back roughly 2.4 million shares from our largest shareholder for $280 million. We continue to see purchasing our stock as the highest and best use of our capital. We have over $100 million of capacity remaining under the current share repurchase program and are working to refresh that capacity. We will provide a capital allocation update during our Investor Day at the start of September. Moving to Slide 11, we achieved an important milestone on July 10th, when Talen rang the opening bell and began trading on the NASDAQ. We believe uplisting to a national exchange has provided several positive impacts for our equity. It improved our trading liquidity and enables a larger universe of investors to access our stock. In fact, we’ve doubled our average daily trading volume compared to three months prior to uplisting. We also had the opportunity to gain access to several equity indices, including potential eligibility for the Russell in mid-2025 and the S&P starting late next year. With that, I’ll hand the discussion back to Mac.

Great. Thanks, Terry. I’d like to reiterate how proud we are of what we’ve been able to accomplish in 14 months, 15 months since we exited restructuring. But we’re not done and we hope to see you at one of our upcoming events. We’ll be hosting an Investor Day in New York, as Terry mentioned, on September 5th. Importantly, during that day, we will discuss our 2025 guidance, our 2026 outlook, and update, as Terry mentioned, our capital allocation plan, as well as discuss long-term growth drivers of the business. Following the Investor Day, we will be on the road in Boston, Los Angeles, Philadelphia and New York, and hope to see you there. We’ll now open the line for questions and turn it back to Michelle, the Operator.

Thank you. Operator Instructions: The first question will come from Michael Sullivan with Wolfe Research. Your line is now open.

Hey. Good morning.

Good morning. Michael, how are you?

Hey, Mac, doing well, thanks. I wanted to just ask, appreciate your comments on the pending FERC process. I guess even if this does go your way, the 480 megawatts, how do you think about the other 480 megawatts that you ultimately have to get approval for and then also your ability to do any other incremental data center deals in the backdrop of everything going on at FERC right now?

Appreciate the question, Michael. As I mentioned, we think that just through the first part, for the first 480 megawatts, we remain optimistic that once we fully answer FERC’s questions, or PJM in this case, with our help with PPL answers, that we’re optimistic that they’ll approve the ISA as submitted. We were disappointed that we received a deficiency letter, but we understand the need for additional time and clarification and wanting to build a fulsome record as they review the ISA. On your second point, we were encouraged by FERC also bifurcating the larger co-locator and data center issues into a separate technical conference, which we’ll participate in. Our view is that we continue to move ahead with AWS at the site under the current ISA for the 300 megawatts that we expect will be approved to hopefully reach 480 megawatts. We’re optimistic that we get there, and we need as an industry to come together and to find a solution and to find one swiftly so that we can all benefit in the economic development that powering the AI economy will bring. We think our deal does that, we think there are other types of deals that will do that, and we look forward to that conversation. As far as what we’re doing, we continue to move forward with the site. I mentioned that we’re confident that we will, in the third quarter, release the $300 million of escrow as we meet certain project milestones and we continue to pursue the data deal as signed with AWS.

Okay. Appreciate all that color there. And then just looking ahead to this next PJM auction, any high-level drivers that you all want to highlight? And then also as it relates to that, as we just look to the analyst day in September, I think you’re going to give some commentary on the 2026 outlook. How do you get comfort out there knowing part of that’s going to be this upcoming auction where results can be variable and you’re still fairly open from an edge perspective?

We will give you the assumptions that go into that outlook so that you can perform sensitivities around it. That’s our plan for the 2026 outlook. There is a visible market for 2026 that we will cite at that point in time when we provide that outlook with respect to power prices. With respect to capacity, that auction is not until December and so we won’t know the outcome there, but we’ll give you an underlying assumption and sensitivities relative to that. As an IPP focused primarily in PJM and without retail load, we are highly levered to the outcomes associated with this, which we think is a good position to be in. With respect to drivers for 2026 and 2027, coming off the 2025-2026 clear and the compressed timelines for the December auction, fundamentally, there’s not a lot that can change supply and demand-wise prior to getting to December. Absent of putting out a formal forecast, I think the pricing backdrop remains constructive, given the tight supply and demand that PJM has.

Yeah. Coming off the heels of the 2025, 2026 clear and the compressed timelines for the December auction, fundamentally, there’s not a lot that can change supply and demand-wise prior to getting to December. So, again, absent of putting out a forecast, I think the pricing backdrop remains constructive, given the tight supply and demand that PJM has.

And we’ll get the parameters next week for the capacity auction. So, Michael, more on that to come. I hope that provided some color around it.

Very helpful. Thanks, Mike. Thanks, Chris.

Yeah.

The next question comes from Angie Storozynski with Seaport. Your line is open.

Thank you. So, just going back to the co-location question, there’s been a lot of discussion, including with your utility partner, about behind-the-meter versus front-of-the-meter co-locations, the sort of planned operating risk that you assume under the current contract. Also, there seems to be little pushback from hyperscalers toward bearing additional charges for transmission in front-of-the-meter contracts. My question is, how do you see those two structures going forward as you try to potentially contract the second unit and maybe look at co-locations of gas plants? And would you be open to potentially changing the current deal structure to front-of-the-meter, again, just to discourage any future pushback at FERC or any other levels?

Good morning, Angie. Good question. If we go back to my opening remarks, the challenge in front of us is the large scale of investment required and the variety of solutions that will be needed. When I said balanced, I meant we’ll need behind-the-meter, front-of-the-meter and other novel models to serve growing demand. We like our current deal and believe it is a quick, cost-effective and reliable solution, but front-of-the-meter deals for gas units are possible and I could see them being connected to and relying on the grid for backup. Over the next five years or so, that could be a model by which new gas assets get built—contracted long-term through hyperscalers for capacity and relying on the grid for backup. It’s important to note that our deal was the first meaningful one and the market is trying to figure out value allocation. The opportunity is so large that we need all solutions on the table and collaboration across industry stakeholders. In short, we are open to different structures, but we like our current deal and think a mix of approaches will be necessary to meet demand while protecting residential customers and maintaining reliability.

Okay. Just one follow-up to that topic. Would you expect different, for example lower, economics for power companies under front-of-the-meter deals versus behind-the-meter just because there’s a higher transmission fee, or would the off-taker—the hyperscaler or other tech company—absorb this additional cost?

Until the first front-of-the-meter deal gets done, it’s hard to generalize. Front-of-the-meter deals must meet tariffs and will likely be negotiated on an ISO- or utility-specific basis. PPL, our partner, has both behind-the-meter and front-of-the-meter solutions, and I expect a combination of those will be used. The models will vary by contract, tariff and local needs. There’s substantial opportunity across all approaches, especially in regions with large prospective builds like PPL’s area. Ultimately, all stakeholders need to find balanced solutions that protect residential rates while enabling economic development.

Okay. Then changing topics, we saw some press reports about your Coin business. Can you comment at all about the future of that business?

What we’ve said is we don’t believe it’s a strategic asset for us and we’re looking at alternatives with respect to Coin. That’s all we have to say at this point in time.

Awesome. Thank you.

And our next question comes from Ian Zaffino with Oppenheimer. Your line is open.

Hi. Great. Thank you very much.

Good morning, Ian.

Good quarter. Thanks for all the guidance and color. Question will be on Brandon Shores and Wagner. How are we thinking about the resolution when it comes to timing? I know there’s an ask, but how do we think about what the EBITDA impact could be or where that settles and all the steps to get us there? Thanks.

With respect to Brandon and Wagner, we said we’ll participate with all stakeholders to come to an equitable solution. We hope to do that by the end of this year. We have started the proceeding, an ALJ judge has been assigned and schedules are being worked through. As a matter of principle, we don’t discuss matters that are in front of FERC beyond procedural updates, so we won’t try to prognosticate outcomes. We are looking for a solution for all stakeholders by year end because if these assets run for the next few years, there are operational and labor considerations, maintenance needs, and other decisions that must be finalized to ensure reliability. We think resolving this before year end is important.

Okay. Great. Thank you. And then on the guidance, can you maybe just talk about what your expectations are for PJM forward pricing, spark spread and how they moved versus what you were expecting?

Hey, Ian. With respect to our guidance, we are using the view of forward prices as of the end of July. If you refer to the slide earlier in the deck, spark spreads have moved around since the start of the year. Since we’re effectively fully hedged for the balance of the year, we don’t have much sensitivity with respect to how 2024 will move. So there’s not a massive impact on 2024 from changes in spark spreads.

Okay. Thank you very much.

And our next question comes from Craig Shere with Tuohy Brothers. Your line is open.

Good morning. Thanks for taking the question.

Good morning, Craig.

On the RMR question, just to dig in a little further, how much could a prospective repowering with the best deployment be on those sites?

I don’t think we’ve put out a specific number on what repowering would cost. It’s more a matter of time. When capacity markets were clearing at $50 per megawatt day, it was uneconomic to convert units. We cannot continue to run the units without some relief of permit issues, as well as an arrangement with Sierra Club past June of next year. I think both of those can be resolved to maintain reliability under the right construct to solve transmission constraints until transmission can be built. If there’s a way to repower the units under a construct that provides an ample return, we would consider repowering to oil and could do so over the next three years. We also have several hundreds of megawatts of battery capacity that could be deployed across Wagner and Brandon. If batteries are a more economic solution for customers in the region, we would look at that as well.

Thank you. And bigger picture: One of the ultimate valuation questions is whether this is really a volatile commodity spark spread story or a systemically shifting capacity market—PPA, RMR agreements—more long-term, stable, recurring free cash flow. Can you provide some color on that?

Sure, Craig. Let me start and have Terry add. Susquehanna provides downside protection via production tax credits and contracted exposure, which creates a floor for part of our portfolio. We have megawatts contracted through the AWS deal that will reach 960 megawatts, and we’re pursuing creative solutions to add more contracted revenue at Susquehanna and other sites. Over time, I expect more of our revenue to come through contracted energy and capacity payments. Since our restructuring, with a cleaner balance sheet and ample liquidity, our commercial team has pursued strategic hedging to capture extrinsic value from our gas assets, as we did in the first half of this year. So it will be a combination: anchored by contracted, high-quality cash flows at Susquehanna, incremental contracted deals, and opportunistic capture of value in the merchant markets. That mix should move us toward more predictable, contracted cash flows over time.

Craig, to add to Mac’s comments, Susquehanna makes up about half of our generation annually, so getting contracted cash flows with a high-grade credit counterparty is very supportive of valuation. Another dynamic is the scheduling around PJM capacity auctions—over the next year you’ll have clears for 2026 and 2027 and for 2027 and 2028, which will provide more clarity on capacity revenue streams across the fleet through part of 2028. That should solidify value and give greater certainty around equity valuation. We’ll continue to build on contracted cash flows for the business.

Great. Thank you.

And our next question comes from Thomas Meric with Janney Montgomery. Your line is now open.

Hey. Good morning, team. Thanks for taking the time and for the color and appreciate the opportunity for the Investor Day in a couple of weeks in New York. Curious on co-location deals for new-build assets and just how the PJM auction potentially changed the price outlook hyperscalers are looking at for co-location deals, whether they’re existing or potentially new built into the future?

Good morning, Thomas. Terry mentioned this earlier: it’s one data point, but this demand will drive the need for increased supply. That need must be balanced with appropriate cost sharing and protection of residential rates. Data centers behave like industrial load—24/7—and will require generation and transmission investments that raise system costs. When the market tightens, you see increased capacity pricing and higher heat rates and spark spreads. Over time, generation will get built and will likely be structured to serve specific loads under PPAs, whether front-of-the-meter with energy components or other models that enable new generation to secure revenue streams. Traditional single-asset SPV models may not provide the portfolio or credit support needed, which is where a company like Talen with a portfolio and balance sheet can participate. Expect a combination of approaches to solve this, including generation built to serve specific loads with contracted revenues and some behind-the-meter solutions.

Thanks. That’s it for me.

I show no further questions in the queue. I would now like to turn the call back to Mac McFarland for closing remarks.

Well, great. Thanks, Michelle. And thanks everyone for joining us and for your questions today. We appreciate your continued support of Talen. As we continue to focus on challenges and opportunities facing the industry, we look forward to seeing you on September 5th. Have a great day.

This concludes today’s conference call. Thank you for participating. You may now disconnect.