Talen Energy Corporation (OTCQX:TLNE) Q1 2024 Earnings Conference Call May 13, 2024 4:30 PM ET
Company Participants
Ellen Liu – Senior Director, IR
Mark McFarland – CEO
Terry Nutt – CFO
Conference Call Participants
Michael Sullivan – Wolfe Research
Angie Storozynski – Seaport Global
Ian Zaffino – Oppenheimer
Operator
Good afternoon and welcome to the Talen Energy First Quarter 2024 Earnings Conference Call. All participants will be in a listen-only mode. (Operator Instructions) Please note this event is being recorded.
I would now like to turn the conference over to Ellen Liu, Senior Director of Investor Relations. Please go ahead.
Ellen Liu
Thanks Donna. Welcome to Talen Energy’s first 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.
I’d like to highlight that we have posted materials on the Investor Relations’ section of our website, www.talenenergy.com (ph) and filed continuing disclosures on the TLNE page of the OTC website that provide additional information about our operations, first quarter results, and other matters discussed on the call today. We have also provided information reconciling our non-GAAP financial measures to the most directly comparable GAAP financial measures in our earnings materials.
Today, we are making some forward-looking statements based on current expectations. Actual results could differ due to risk factors described in our financial disclosures and other periodic public filings.
As a reminder, we have allotted additional time for a question-and-answer session at the end of our prepared remarks. We ask participants to please limit their questions to one primary and one follow-up.
With that, I will now turn the call over to Mac.
Mark McFarland
Great. Thank you, Ellen. Good afternoon everyone and thank you for joining us today. As Ellen mentioned, we have posted an earnings presentation and Terry and I will reference those slides as we go through our prepared remarks.
Starting on Slide 3 and with Q1, we are pleased to report strong operational and financial performance. Our fleet generated $289 million of adjusted EBITDA and $194 million of adjusted free cash flow in Q1, largely driven by realized hedge gains of $165 million from our commercial hedging strategy.
On that, we are updating our 2024 guidance to remove the ERCOT fleet going forward and increasing guidance on our remaining fleet for higher forward prices and spark spreads, along with lower interest payments from our term loan repricing. Our new guidance ranges are adjusted EBITDA of $600 million to $800 million and adjusted free cash flow of $160 million to $310 million.
We are off to a strong start in 2024 and we unlocked value in multiple ways this quarter. As announced on our Q4 call, after observing an opening in the ERCOT M&A market, we launched the monetization process for our 1,700-megawatt ERCOT fleet in late 2023. Earlier this month, we closed the sale of those assets to CPS Energy for $785 million gross, capturing a valuation materially higher than consensus estimates.
We successfully completed a repricing of our term loan B and C on May 8, decreasing the interest rate by 100 basis points, which drops annual interest by approximately $13 million.
We also obtained a waiver on our debt paydown requirement for the estimated $723 million of net proceeds from the ERCOT sale and achieved other amendments in our credit agreements. All of this enabling greater capital allocation flexibility.
I will also note that S&P upgraded our outlook to positive in early April and continues to maintain that outlook after the term loan repricing. As many of you know, in March, we announced the sale of our Cumulus data assets to AWS for $650 million, along with signing long-term revenue contracts. Since then, we started earning revenues from AWS and anticipate the release of the $300 million of sales proceeds currently in escrow in the second half of 2024.
The monetization process for our interest in the Nautilus Bitcoin mine is progressing, and we remain committed to exiting the Coin business in a value-accretive way. We also continue to explore how to leverage our recent data deal for other potential opportunities across our fleet.
In the fourth quarter of last year, we implemented a $50 million cost savings program and we have achieved $45 million of the target to-date. We expect to achieve the full amount by year end and continue to look for ways to save on expenses and optimize our cash flow per megawatt.
Finally, we continue to focus on the most effective way to return capital to shareholders. Under our existing $300 million share repurchase program, we bought back 493,000 shares to-date for a total of $38 million.
Today, we are upsizing our remaining share repurchase capacity to $1 billion. This SRP is evidence of both Management and the Board’s conviction in our operating performance and long-term cash flow generation profile.
We continue to work towards uplisting on a major national exchange and recently announced that we will be refreshing our draft S-1 for the Q1 financials. The SEC will need to complete its review of our S-1 before we can uplist or before our uplisting can become effective.
In the interim, as announced last month, we are planning to execute a CUSIP exchange to maximize equity liquidity and transparency for our investors. As a reminder, we have two classes of shares. The 1145s that are quoted on OTCQX and the 4A2s, which trade in private transactions.
One year after emergence, which is May 17th, we can exchange our 4A2s for 1145, which will allow all shares to be quoted on the OTCQX. This will enable our shares outstanding to become — become more visible liquid and accessible to a broader universe of investors.
Turning to Slide 4. Let’s look at our operational and financial results in more details. Our fleet ran well, generating 8 terawatt hours with an EFOF of only 1.9%, and 58% of that generation comes from our carbon-free Susquehanna nuclear facility, which also started its spring refueling outage in the first quarter and was successfully completed in April.
Importantly, our whole team worked safely with a strong total recordable incident rate of only 0.3%. Historically, this is in line with or better than our peers, and we continue to emphasize safety as our first priority across the fleet.
We continue to prioritize capital discipline and balance sheet management during the quarter. We currently have nearly $2 billion of liquidity, thanks to the recent asset sales and cash from operations.
With that cash balance, our net leverage is only 1.2 times, far below our 3.5 times target. This enables us to return more capital to shareholders, and Terry will touch on this later.
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 across our entire fleet.
The past couple of months were the busiest time of the year for many of our operations team members as they successfully navigated our spring outage schedule. These team members are key to the overall financial 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.
I’d also like to commend the Talen commercial and risk teams for implementing a highly successful 2024 hedging strategy, capturing significant margin during the down market of Q1.
Turning to Page 5. Our good performance this quarter tees us up to take advantage of exciting market trends. Let’s talk about why now is the best time to be a pure-play IPP. Many of you have seen industry reports from Mackenzie, Goldman Sachs Research, BCG, and others talking about the accelerating load growth and supply/demand factors driving this growth. These trends impact the entire U.S., but are especially acute in PJM.
For those of us that have been in the power sector for many years, we have seen multiple boom-bust cycles, but things are different now. Over the last 10 to 15 years, load growth flattened out as energy efficiency increased and commercial load began being replaced by — commercial load began replacing around-the-clock industrial load.
Furthermore, there was a lot of relatively cheap and abundant natural gas from the shale boom and power and capacity prices also became flat to declining. From a supply perspective, limited demand created excess capacity that intersected with the rise of ESG mandates; plants ran less, earned less, and face more stringent environmental restrictions.
So, we began seeing large retirements of coal and inefficient gas-fired generation assets in favor of developing renewables, thus substituting more intermittent forms of power generation for units that ran around the clock or baseload. Battery storage development also began, but is still in its early innings and not at commercial scale.
Today, the demand picture is much different, while the supply picture has not kept up. U.S. power demand is forecasted to grow at 1.5% per year over the next decade per IEA. The primary drivers are data centers, industrial and manufacturing, and the electrification of transportation and buildings.
Much of the new load growth requires baseload reliable energy like a nuclear plant. Reliable power is scarce and reliable low-carbon power even more so, especially as large power consumers continue to work towards their net zero targets.
As many of you know, the rise of AI has greatly accelerated data center growth with tech companies like Amazon, Google, Microsoft, and Meta budgeting over $200 billion in CapEx in 2024 alone.
Data centers can consume 10 to 50 times the power of an office building with AI on the upper end of that range. Meanwhile, on the supply side, there is minimal excess capacity and given the build-out of intermittent generation, that minimal excess capacity has limited dispatchable generation.
Market economics and EPA regulations have continued to incentivize fossil retirements and the development of new generation has not filled the gap. Development queues are still mostly renewables and longer-duration battery storage has not progressed far enough to solve the intermittency problem.
Thermal newbuilds have long lead-times and the new GHG rules issued by the EPA in April may make them even more challenging to construct. Existing dispatchable generation is becoming increasingly critical to grid stability and the supply/demand mismatch is now triggering reliability actions like RMRs.
We’re starting to see the capacity and energy markets respond as well with long-term power prices increasing despite gas prices remaining low, which has led to a significant spark spread expansion.
These dynamics have created several attractive value catalysts for IPP, a significant data center market opportunity, combined with increasing power prices in spark spreads, higher capacity revenues, all alongside downside protection through the nuclear PTC.
We are one of the few pure-play IPPs in the space without retail load. We have both reliable baseload power, including nuclear, and a dispatchable gas fleet. We enjoy the downside protection from the PTC on approximately 50% of our generation and PJM capacity revenues on most of our fleet.
We have full exposure to the price and spark spread improvement through our commercial hedging strategy, dispatchable fleet, and the lack of retail load. And lastly, we are the only one so far who have done a behind-the-meter data center deal that includes an attractive PPA with a AA credit counterparty. Talen’s ability to capture all three of these key value catalysts gives us visibility to a greater than 10% adjusted free cash flow CAGR over the next five years.
Let’s look at Slide 6 and how it takes a closer look at the PJM wholesale market is starting to respond to the supply/demand dynamics laid out on the prior slide. Both forward prices and spark spreads in 2025 and 2026 are up when comparing today versus year end 2023, particularly in the winter and summer months.
These pricing improvements flow through to the earnings of our baseload nuclear plant and coal fleet through a relatively simple P-times-Q or price times quantity calculation.
When power prices increase, plants like Susquehanna generate more. However, what about our gas plants? The increase in spark spreads could also translate to significant upside for them, but how do we realize that? We use two primary tools to monetize our exposure to the PJM market opportunity; physical generation and our commercial hedging strategy.
I will now turn the call over to Terry to unpack how our gas plants can capture these increasing sparks.
Terry Nutt
Thank you, Mac and good afternoon everyone. As Mac mentioned, Talen’s PJM gas fleet is well-positioned to benefit from increasing power prices and expanding spark spreads. We believe our diverse fleet of gas-fired assets provides a significant source of upside to commodity price dynamics.
As you may know, these intermediate and peaking plants run for a portion of the year, largely dependent on the economics of power and fuel prices. When spark spreads expand, two things happen to our gas fleet; first, new generation becomes in the money or profitable; and second, existing generation becomes deeper in the money. This could have a multiplier effect on generation margins.
On slide 7, we’ve provided an illustration of how recent spark spread moves impact our gas fleet. When we compare pricing as of December 29th versus March 28th, you can see that a percentage change in spark spreads could have a significant impact on expected generation and margin.
For example, 2025 average forward spark spreads between those dates were up approximately 11%, while the expected generation from that price move increased 13%. Furthermore, those changes resulted in an overall increase in our gas fleet gross margin by 30% or approximately $50 million.
For 2026, a similar dynamic takes place, with an 18% increase in spark spreads, resulting in a 24% increase in expected generation volumes and ultimately, a 45% or $75 million increase in gross margin for our gas fleet.
Load growth has been accelerating and the wholesale market has only recently started to respond with power prices decoupling from their traditional correlation with natural gas, resulting in widening spark spreads across the forward curve. This resulting impact will further boost the earnings potential of our PJM gas fleet and our baseload generation assets as well.
Turning to Slide 8, let’s look at the other tool that we use to manage our earnings and cash flows, our hedging program. Our commercial hedging strategy is pragmatic, not programmatic. Our approach allows us to remain nimble in the face of ever-changing market conditions.
While we do have targets and risk management guidelines, we adjust our strategy as needed based on the outcomes and outlook of several different variables. This program focuses on more than just solving for a certain view on prices.
Let me walk you through our process at a high level. First, we established a base level of hedging needed to protect cash flows and earnings to operate the business and service our capital structure.
From there, we account for various considerations, such as counterparty risk and trading liquidity limits to establish the boundaries of our hedging program. With those factors in consideration, we develop our point of view about power markets and execute hedges to maximize upside, while keeping an eye on other sources of risk, like operating risk and regulatory developments.
After we execute a hedge to lock in earnings and cash flow stability, we then move to a second set of decisions. As the delivery date approaches, we are routinely presented with the decision to either make or buy the generation we’ve hedged based on how the power markets are settling.
For example, if power prices in the day-ahead market are lower than our marginal generation costs, we can achieve incremental value by buying power on the open market to satisfy our hedge obligations.
Turning to the right side of the slide, you can see our commercial hedging program at work in a table with sensitivities assuming various power price changes. The implications of the nuclear PTC and other strategies help us to achieve asymmetric outcomes with more upside potential, while also protecting downside.
For example, in 2025, a $10 per megawatt hour price increase could lead to a $265 million gross margin increase, while a $10 price decrease results in only $115 million expected margin decrease.
You’ll notice that our 2026 hedge percentage is lower than prior years. That’s primarily because of a couple of reasons. First, the 2026 price curve as of March 28th is higher than prior years, resulting in minimal expected impact from the nuclear PTC.
And secondly, we currently like the market dynamics that are occurring in the outer years as the forward curves begin to factor in higher load demand. We’ll continue adding 2026 hedges as market opportunities arise in the coming months.
In summary, our hedging strategy preserves margin, provides cash flow stability, and generates upside in a variety of market conditions. In fact, hedging played a critical role in achieving our Q1 results.
Moving to the next slide. For the first quarter of 2024, Talen reported adjusted EBITDA of $289 million and adjusted free cash flow of $194 million. Our commercial hedging strategy protected margin in the face of weak winter prices. Earnings for the quarter benefited from $165 million of realized hedging gains that offset lower power prices.
As Mac noted earlier, we also continued progress on our previously announced cost savings plan, completing over 90% of the initiatives identified to reduce O&M and G&A costs in 2024 and beyond by $50 million per year. We are confident that we will achieve this target by year end.
Let me provide some more regional detail on the wholesale power markets. In both PJM and ERCOT, Q1 weather was unseasonably warm, with heating degree days below the 10-year averages, resulting in lower demand and consequently lower power prices.
However, our earnings and cash flows were protected by hedge program gains, particularly in PJM. The PJM segment earned $279 million of adjusted EBITDA during the quarter, while the ERCOT and WEX (ph) segments earned $15 million of adjusted EBITDA.
Turning now to guidance on Slide 10. We had several factors influencing our guidance update this quarter. The three primary factors include the selling of our ERCOT generation fleet, the repricing of our term loan debt, and the increase in spark spreads that expanded in the second half of this year.
Consequently, we are updating our 2024 adjusted EBITDA and adjusted free cash flow ranges to remove approximately $70 million of earnings from the ERCOT fleet for the balance of 2024, while modestly increasing earnings for the rest of the business by approximately $30 million for forward power price growth and spark spread expansion.
Our new adjusted EBITDA range is $600 million to $800 million. We’re also revising our adjusted free cash flow to $160 million to $310 million, which includes approximately $5 million of lower expected interest payments.
As a reminder, our business is seasonal and we make most of our money during the core winter and summer months of Q1 and Q3, while Q2 and Q4 are shoulder periods from an EBITDA and adjusted free cash flow perspective.
I also want to remind everyone that certain periodic cash payments happen in the second and fourth quarters. For example, our debt service payments and CapEx associated with our spring and fall outages occurred during those periods.
Moving along, we remain committed to maintaining net leverage below our target of 3.5 times and using excess cash flows to maximize return on capital and share those returns with our equity holders. Thanks to our ongoing operations and financial results, along with recent transactions, our balance sheet and liquidity are the healthiest they’ve been in a long time.
As of May 6th, our forecasted net debt-to-EBITDA ratio using the midpoint of our 2024 adjusted EBITDA guidance is only 1.2 times, well below our 3.5 times target. In addition, we have nearly $2 billion of liquidity, including approximately $1.35 billion of unrestricted cash.
I think it’s important to point out that even if we were to utilize the entire $1 billion of our upsized share repurchase program in 2024, our net leverage ratio would still only be 2.6 times.
To further bolster the health of our balance sheet, we recently successfully completed a repricing of our term loans, lowering the interest rate by 100 basis points, which is expected to generate approximately $13 million of annual interest savings.
We also obtained a waiver of the mandatory prepayment of the term loans with proceeds from our ERCOT sale and executed amendments increasing our capacity for restricted payments and investments under our main credit agreement. These allocation — these actions provide Talen with additional capital allocation flexibility.
On the topic of capital allocation, let’s look at Slide 12. As Mac mentioned earlier, our successful operation and transactions have resulted in over $1 billion of available cash on the balance sheet.
Given this ample liquidity and our continued modest leverage profile, our Board has authorized an increase in our remaining share repurchase capacity to $1 billion. The program still runs through year-end 2025 and we will execute repurchases on an opportunistic basis.
At recent share prices of approximately $105 to $110 a share, a $1 billion share repurchase program reflects approximately 16% of our current market cap. This demonstrates our continued focus on returning capital to shareholders and continued belief in the value of our business.
To-date, we repurchased 493,000 shares for approximately $38 million, implying an average price of approximately $78 per share.
With that, I’ll hand the call back to Mac.
Mark McFarland
Great. Thanks Terry and thanks for everyone joining us today and your interest in Talen.
With that, we’re going to turn it over to the operator and take questions.
Question-and-Answer Session
Operator
Thank you. We will now begin the question-and-answer session. (Operator Instructions)
Your first question comes from the line of Michael Sullivan from Wolfe Research. Your line is open.
Michael Sullivan
Hey, good afternoon.
Mark McFarland
Hey Michael.
Michael Sullivan
Hey Mac. Thanks for all the new disclosures around sensitivities and hedging. Can you give us any color around how just 2025 and 2026 may be tracking relative to 2024, so we have a sense for what the base is to sensitize off of?
Terry Nutt
Yes, Michael, this is Terry. I’ll take that question. I think when you look at 2025 and 2026, obviously, as noted in the prepared remarks, we’ve seen a move in spark spreads. So, we tried to highlight that for everybody from a modeling standpoint.
I think the other thing that you have to layer into that is — and Mac noted this earlier in his prepared comments, is we’re starting to lay in the AWS contract and starting to see earnings from that in both of those years.
And so I would refer back to the material that we previously provided on the impacts of that transaction. But starting from sort of the 2025 — or the 24 standpoint, you can add those incremental items and sort of get a directional view on 2025 and 2026.
Michael Sullivan
Okay, that’s very helpful. And then when we just think about your cash position right now, sort of $1.4 billion in unrestricted cash, and I think you said you have another $300 million coming from the AWS transaction later this year.
As we match that up with the increased buyback today is just simple math, $1.7 billion, less the $1 million, the remaining $700 million, is that spoken for or could potentially be available as well? How do we think about that?
Terry Nutt
So, Michael, good question. I think a couple of things on that. I would refer to the comments that I made earlier. When we get to Q2 and Q4, we do have higher cash needs for the business and so you have to factor those into consideration. But generally, yes, you could factor additional cash or other activities as we move forward around shareholder returns.
Michael Sullivan
Okay. Thanks very much.
Operator
Your next question comes from the line of Angie from Storozynski. Your line is open.
Angie Storozynski
Thank you. So, first, the 10% CAGR or above 10% CAGR for free cash flow, that looks actually pretty low to me given just the drivers you just laid out the AWS and the pickup in spark spreads, not to mention a likely pickup in capacity prices. So, is it meaningfully above 10%? I mean, again, that number looks very low.
Mark McFarland
Well, first of all, Angie, how are you? Good to hear from you. Well, look, I think that we’ve demonstrated a track record of — hopefully, we’ve demonstrated a track record, let me say it that way, of being conservative and being committed to delivering on expectations.
And so when we look at out there, we wanted to provide some indication of what the next five years looks like. And I think the point that we’re making is that, that visibility — we have visibility to that. And a lot of that comes through contracted revenues, not just increase in sparks that are in the out years that are — when you get out to years four and five, there’s not a lot of liquidity in the power markets. And so we are seeing that and have the opportunity to realize that increased growth through the AWS contract as well as these sparks.
But look, we have not provided — I think Michael was asking the question before. It’s been a while since I think the January 27th disclosure of last year during bankruptcy that we provided out year guidance, and that’s not lost on us.
We’re in the process of doing that. We’re just in the early stages of doing it, and we’ll provide an update on the guide, but we wanted to give people a view of having some direct visibility to cash flow growth.
Angie Storozynski
Understood. And then besides the buybacks, is there anything else that you guys are working on? I mean — and the buybacks and the uplist, I guess. But now that Cumulus has been monetized, are you guys working to replicate this strategy at other plans? Is that — are you looking at any potential combinations with either public or private IPPs? Is there any thought about maybe enlarging the existing portfolio, again, to either a large M&A transaction or asset-based transactions?
Mark McFarland
Yes, I appreciate the question and I like your persistence on it. As you know, we don’t comment on M&A, but I will tell you the same thing. We did mention that we’re looking to release the escrow. That’s a big deal for us, right, to get that done, the milestones as part of that deal as well as we’re starting to collect revenues from the long-term contracts with AWS.
And then we’re looking to implement that because we’ve laid out a schedule as everyone knows, on March 4th, where we showed half campus build, full campus built. We’re looking to do as much as we can to make sure that that becomes more and more real and sooner rather than later.
We’re also working on the Coin aspect, as I mentioned, that we’ve — I wouldn’t say it’s necessarily a mandate, but we are saying that we’re going to get out of Coin at the right value.
And so we’ve got a lot going on there and we also just completed the transaction, ERCOT and closed that, and that was just on the heels of AWS. So, — and then we repriced the term loan.
So, I think we’ve been doing quite a few things, quite frankly. But — and we’re going to continue to do so. And — but we don’t talk about some of the other stuff that we could or could not be working on. We’ll let you know when we get them done.
Angie Storozynski
Okay. And the last one about PJM capacity prices. So, we have these two auctions this year. The first one is probably not — well, still have some rule changes that will not be implemented. But I’m just wondering, your set of assets seems uniquely sensitive to capacity prices in PJM. So, I’m wondering how you see those evolving?
Mark McFarland
Well, look, we’ll see where the auction clears, don’t want to front-run the auction. We do think that the power markets are tightening and that would — should be reflected in the capacity markets.
If you look at the last couple clears for RTO and MAC (ph), they’ve been fairly low. And I think you see continued retirements and also new rules that are tightening the markets.
And I think — by the way, our gas plants, I think — I hope one of the things that Terry went through is that, yes, while those gas plants in the past or last couple of years have been more of a capacity play, as you mentioned, going forward, and if you look at the expanding sparks and I forget what the exact slide number that is there, Terry, but the — 7 — these gas plants are becoming more and more in the money generation, if you will, as sparks expand. And so they are both a capacity and an energy spark play.
But we’ll have to see, Angie, when it comes to the — I don’t like to front-run those. We have our views, but we do think that the markets are tightening and should be reflected in the next 2025, 2026 auction in July.
Angie Storozynski
Great. Awesome. Thank you.
Operator
Your next question comes from the line of Ian Zaffino from Oppenheimer. Your line is open.
Ian Zaffino
Hey great, Donna. Thank you very much. I know you guys gave us a little bit of an update on the potential for other data centers at some of your other locations. You had ongoing discussions about that and if that’s the case, what would you need to create data centers or at least make the facilities available for a data center, either let’s just say, a coal strip or lower (Indiscernible)? Thanks.
Mark McFarland
Yes. Hey Ian, good to hear from you. Look, I appreciate it, it’s a fairly open-ended question. I think that what we’ve been able to create in a first-mover advantage, if you will, with the AWS transaction is to demonstrate that we learned a lot on how to contract and how to contract long-term in a data center capacity and obviously, we’re going to look to leverage that.
But we don’t — there’s nothing that we can comment on right now other than say that it’s a little bit interesting to say, well, we’re looking at it, and we’re working on it. But that’s what you’re going to get because we don’t talk about commercial activities until we’re done.
Ian Zaffino
Okay. And then on the $1 billion buyback or potential. Any thoughts on how you’re going to do that or to be a Dutch? Would it just be over market purchases? What should we expect on a way to return this much capital? Thanks.
Terry Nutt
Thanks Ian, this is Terry. Definitely by way. Yes. So, with respect to the share repurchase program, we’ll utilize a number of different avenues for that at the end of the day. And I guess what I would commit to you is, number one, the $1 billion has been approved by the Board. And so that is locked and loaded, and we’ll execute that between now and the end of 2025.
I think the other thing is we want to return money to our shareholders in a timely manner. And so we’ll move with purpose when it comes to doing that. So, hopefully, that gives you a sense of the direction of travel with respect to the share repurchase program.
Ian Zaffino
All right. great. Thanks for the color. Good quarter and thanks for all the answers.
Mark McFarland
Thanks Ian.
Terry Nutt
Thanks Ian.
Operator
(Operator Instructions)
Your next question comes from the line of Hamid (Indiscernible). Your line is open.
Unidentified Analyst
Hi. So, my question was really about when you look out to 2026 and you’re seeing this kind of demand and the expectation that demand is going to go up, what’s the risk here that you have regulatory action where it increases the supply? And obviously, the nation is not going to run out of electricity.
Mark McFarland
Yes. Well, it’s a good question. I mean if you look at the market and particularly the market that after we’re out of ERCOT, we’re now principally in PJM. The entire concept of the capacity market that has been introduced that has been revamped several times, and we’re getting ready to do an auction here for next year’s planning year, 2025-2026, which used to be — it was intended to be three years in advance.
The concept of that market is to drive and to send signals for new build generation. And so hopefully, when we get back to steady state capacity markets, that will send a signal for growth.
Now, I think that there’s a lot of perhaps externalities that are going to be consequential when it comes to new generation coming on, which is regulations. There’s been a huge push to go towards renewable generation, which is not dispatchable. And renewable generation is typically — as well as some new build thermal generation is typically away from load centers, which requires additional transmission build as well. And so I think that all of those can be solved over time, okay?
If you look at, for example, I mean, just look at the RMRs that we filed at Brandon and Wagner, there is transmission upgrades that are going to come to relieve that, but it’s going to take, as estimated by PJM, at least three years to get that done and $800-plus million of transmission.
So, I think all of those constraints will eventually resolve themselves and they will because we — because of energy security, and we won’t let the lights necessarily go out as a country, but they will take time to resolve.
And I think in the past, the response has been that there has been a queue that could be ramped up and hit the grid quicker. But we have not seen CCGT build to any material size. I think some of the financing and the raising of money around that has atrophied as well. And so you’re going to see those be longer lead-time items. And I think that there’s other places in the world that you’re starting to see supply chain issues associated with gas turbines.
So, there’s a lot that needs to get resolved in there. And hopefully, we get back to a capacity market that sends a three-year forward signal that allows for this to work its way through the market.
Unidentified Analyst
Okay. I appreciate that. And then my follow-up was going to be, you have a plant that says being asked to be kept online that you were going to retire here. Is there going to be any increased CapEx, if you look out into 2026 and that plant stays online because of the current situation you’re describing?
Mark McFarland
I mean, yes, we have filed with FERC and those are on the docket, you can look there. And if you need to, we can follow-up with you and get to those dockets, but we filed our costs associated with it and includes CapEx.
One of the things when you look to, for example, at Brandon, which was — is a coal facility in the Harbor there in Baltimore, the coal facility that you expect to shut down and we had said that it was going to be shut down in May of next year, June 1st, effectively May 31st of next year, 2025, that obviously, you don’t necessarily starve anything of CapEx, but you don’t necessarily plan to run it for three more years. And so decisions are made around that.
And those decisions will have to be reversed and there will have to be capital that goes in, in order to ensure the reliability of Brandon when it’s called upon to relieve transmission constraints under a RMR agreement.
Unidentified Analyst
Okay. Thank you.
Mark McFarland
But it would be included in the cost of that RMR just to be clear. And so it’s — those costs are included in that docket that I was referencing at FERC.
Unidentified Analyst
Great. Appreciate it.
Operator
There are no further questions at this time. I’d now like to turn the call back to Mac.
Mark McFarland
Well, great. Thanks everyone for joining us today and for your continued support of Talen. We really believe we’re at the intersection of some interesting catalysts as a pure-play IPP, the data center opportunity, spark, and power price expansion, combined with downside protection of the nuclear PTC. It’s really an exciting time for us. Thanks and have a great day.
Operator
Thank you for participating. You may now disconnect.
