Hallador Energy Company (HNRG) Q3 2026 Earnings Report, Transcript and Summary

Good afternoon, and welcome to Hallador Energy Company's Third Quarter 2026 Earnings Conference Call. [Operator Instructions] This call is being recorded. I now will turn the call over to Sean Mansouri with Elevate Ir. Please proceed.

Thank you, and good afternoon, everyone. We appreciate you joining us to discuss our third quarter 2026 results. With me today are Brent Bilsland, Chairman and Chief Executive Officer; and Todd Telesz, Chief Financial Officer. This afternoon, we released our third quarter 2026 financial and operating results in a press release that is now on the Hallador Investor Relations website. Today, we will discuss those results as well as our perspective on current market conditions. Following prepared remarks, we will open the call to answer your questions. Before we begin, a reminder that some of our remarks today include forward-looking statements, including statements about Turtle Creek, the final investment decision we are targeting, its cost and timing, interconnection and construction, long-term contracts for its output and financing, refinancing and a potential sale of an interest, our contracted forward sales, the availability and reliability of Merom, our estimates of the potential value of Turtle Creek and market conditions, including demand for and pricing of power and capacity, all of which are subject to a variety of risks, uncertainties and assumptions described in today's press release, our quarterly report on Form 10-Q for the quarter ended September 30, 2026, and our annual report on Form 10-K for 2025, each of which is available on our website and at sec.gov. While these forward-looking statements are based on information currently available to us, if one or more of these risks or uncertainties materialize or if our underlying assumptions prove incorrect, actual results may vary materially from those we projected or expected, including because we do not yet have a signed offtake agreement for Turtle Creek, the interconnection agreement has not been executed. We have not secured commitments for the additional capital we will need. Costs may exceed our estimates or construction may be delayed. Our debt requires a minimum return on repayment. Merom may not be available or reliable. Our forward sales contracts include unit contingencies, volume options and regulatory approvals or market conditions change. Our estimates of the potential value of Turtle Creek and the goals and targets we discuss reflect management's current assumptions. They are not guidance or a prediction of our stock price. In providing these remarks, Hallador has no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, unless required by law to do so. And with the preliminaries out of the way, I'll turn the call over to Chairman and CEO, Brent Bilsland.

Thank you, Sean, and good afternoon. Before we get into the details, there are 3 points from the quarter I want to highlight. First, Merom generated more than 1.4 million megawatt hours with 1 unit maintenance outage for part of the quarter. Second, we made our third large Merom sale of the year with record capacity pricing. The capacity and energy pricing combined is over $80 per megawatt hour and about 95% of Merom's accredited capacity is now sold through 2035 to investment-grade utilities. Third, we are working towards a final investment decision on Turtle Creek before the end of the year. Over the next 24 months, we'll seek to roughly double an $800 million project into $1.6 billion of value, which we'll walk you through further during the call. With those highlights in mind, we'll cover 5 topics this afternoon: how Merom is running, how we're contracting it, where Turtle Creek stands, what comes next, how, where and when we expect to create value and how we intend to finance the remainder of Turtle Creek project. Todd will take you through the numbers. First, operations. Merom's uptime improved significantly during the quarter. As previously discussed, we took a major scheduled outage on one of the units at Merom in the second quarter. As planned, the outage ran into July. And when the unit came back, there were some teething issues as you'd expect after one of the largest maintenance outages we have ever performed. Once those resolved, both units ran well through the rest of the quarter. All said, Merom generated more than 1.4 million megawatt hours in the quarter with 1 unit in scheduled outage for part of it. For reference, our forward sales table assumes 5.2 million megawatt hours of annual generation. Energy prices are up roughly 20% this year, and the forward energy curve is up as well for the next several years. At those prices, the market is calling for Merom to run nearly all the time. So the question at Merom is a simple one. How many hours each year are the units available? The market is valuing Merom's operation at a high price, and we are focused on investing in the plant to make it run as much as possible. At Merom, we focus on 3 things: people, plant and process. Starting with people, we were fortunate to add several very talented operators to key management positions this year. Good operators want to work at a plant with a future, and Merom has one. Long-term contracts and an owner putting money into the machine and its reliability. When it comes to the second quarter, the planned maintenance outage was a big item on the list and is complete. We will keep investing in the plant's mechanical systems so the units are available more hours each year. On process, we're introducing AI tools to help our people see problems coming and find solutions sooner. This includes an operational AI tool that integrates real-time data to interpret and anticipate problems within the plant and provide proactive solutions that help reduce downtime. Our second topic is contracting. This year, we have had great success contracting Merom's output. We made large sales in March, May and October, each priced higher than the one before, and the forward sales book now sits at about $3 billion, including $0.5 billion of intercompany coal sales. The details are in the forward sales table in the October release and again in this afternoon's earnings release. About 95% of Merom's accredited capacity is under contract through 2035 and roughly 2/3 through 2040. Taking capacity and energy together, we're selling at $46 a megawatt hour for the rest of this year, $59 next year, $70 in '29 and $75 from '31 through '35. That position provides revenue visibility subject to unit contingencies, volume options and other terms described in our filings. These are the blended per megawatt hour figures in the forward sales table, which use the tables generation assumptions and include our estimates of energy revenue. The majority of those sales are with investment-grade utilities or carry a parent guarantee from one. Historically, these are very reliable agreements. We believe the credit risk in our book is low. Our revenue, therefore, largely depends on what we can control, keeping Merom available to run. As demand for electricity has grown, the prices we have contracted have risen with each sale, and we believe that gives us a good line of sight to development opportunities such as Turtle Creek. We are proud of this book, strong margins, investment-grade customers and high-quality long-term contracts, all of which we believe are key differentiators for our company. We generally target selling about half of our output as unit contingent energy, 1/4 is firm and 1/4 is merchant. Unit contingent means that the unit is down, we don't have to bid it into the day-ahead market. It also means we can take a unit down for maintenance without owning the market for power we aren't making. The exposure that remains is a unit that trips after we have committed it for the day, in which case, we cover the balance of that day. That happened a few times this year and partially offset our results in the third quarter. And it's one more reason we're focused on increasing the reliability of Merom's hours. Unit contingent is lower risk than a firm sale, and it prices roughly at a 15% discount to firm energy. Let me describe the October agreement in some detail because it shows what we mean by quality. The deal is about $700 million of capacity and energy over 6 years beginning in 2029 at the highest capacity price we have contracted to date, more than 20% above the pricing we reported in March. Roughly $420 million of the $700 million is our estimate of unit contingent energy revenue rather than a fixed commitment. Capacity and energy together, the price is over $80 per megawatt hour, the highest number on our forward sales table. I want to be very clear about one point. We sold to an investment-grade utility, not a data center. Data centers may be driving nearly all the growth in utility load, but our counterparty is an investment-grade utility that serves its whole territory, and it pays us whether any particular data center gets built or not. The energy sale is unit contingent and the utility may only reduce its purchases to 0 for up to 90 days per contract year. The price carries a fuel floor and recovers excess fuel cost. So the customer, not Hallador, carries fuel risk for the life of the contract. The agreement took effect on signing and required no regulatory approval, and there are no margin calls. We can see some economics to reduce our risk, and the contract is structured to protect our margins over a long period of time. All of these factors combined point to the value of Merom. The financing trouble that has made headlines in the AI industry recently involves the Neo cloud. Companies that buy computing hardware with borrowed money and rent it out with little revenue from anything else. The hyperscalers borrow too, but they borrow against investment-grade balance sheets and hundreds of billions of dollars of operating cash flow from businesses that have little to do with AI. We understand why the credit market is nervous about the Neo clouds, but they are not our customers, and they are not our credit risk. Nearly all of our contracts are with investment-grade utilities and cooperatives will carry a parent guarantee from the utility. And the utilities customers are the ratepayers of Indiana and the hyperscalers, which have deep access to capital. We believe demand for accredited capacity in our market will keep rising in the near term and the long term. The AI race is really about which companies can get enough power, and we are in that race as the supplier to the utilities. A few weeks ago, a utility in Northern Indiana announced a 20-year agreement to serve a hyperscaler's data center campus, requiring about 1.1 gigawatts of new resources starting in 2028. And the hyperscalers have signaled larger capital budgets for 2027 versus this year. The supply side moves slowly. MISO's traditional interconnection process is backlog for years. The grid moves far more slowly than Silicon Valley because it's regulated and it needs permits. Turtle Creek is gaining access to the grid through MISO's expedited program, and I'll say more about that in a moment. The equipment to build power plants is sold out through 2030 and beyond. And buyers are hunting for gas turbines on the secondary market, which is where we bought the Turtle Creek turbines. The new gas plants announced in Indiana won't arrive until 2029 and later. So our project has a cost advantage and a speed-to-market advantage. The data center build-out faces headwinds in this country. States such as Texas and Virginia and others have slowed or paused their data center build-outs. But roadblocks elsewhere route projects to Indiana. Indiana is open for business. Put it together, demand is rising here, supply can't answer for years and data center projects are arriving from elsewhere. We believe demand is likely to keep outstripping supply in our market for some time. That is what the pricing and our own contracts has been telling us. Against that backdrop, we are pursuing additional long-term contracts for both Turtle Creek and Merom. Our third topic is Turtle Creek. The turbines and generators have been exported from the Philippines. Title has transferred to Hallador, and we expect the equipment to arrive in the United States later this year. The turbines and generators have never been operated. We have filed the air permit application. And since we last spoke, MISO has notified us that the interconnection study, which ran through MISO's expedited resource addition study program is complete. We are now finalizing the interconnection agreement, which has not yet been executed. Our goal is a final investment decision on Turtle Creek before the end of the year, which remains subject to Board approval. We are finalizing the engineering and construction agreement and the bids and purchase orders for the balance of the equipment. Commercial operation is targeted for the second half of 2028 as announced earlier this year. Some have asked why we would make a final investment decision without signed offtake agreements. The answer comes down to scarcity. Turbines are scarce, and we own ours. Interconnections are scarce, and ours is nearly done. The MISO study is complete, and we are finalizing the agreement. Buyers for the output are not scarce. Turtle Creek is a gas plant, and we have seen interest from roughly 4x as many parties in its output as in Merom's because there are fewer restrictions on who can buy gas. We are targeting to sign long-term contracts for Turtle Creek's output early next year. On fuel, we're contemplating tolling the units where the customers bear the cost of the gas, which is intended to limit our exposure to gas price and fuel availability risk. Our fourth topic is where value comes from. We believe our share price today ascribes little or no value to Turtle Creek. I want to highlight 2 ways to look at it. The first is the steps. Turtle Creek is by our current estimate, roughly an $800 million project, and our goal is to turn it into roughly $1.6 billion of value in about 24 months. We think about value creation in 4 steps: acquisition of the equipment, permitting, commercialization and operation of the plant. Based on our current estimate, we believe each step has the potential to contribute approximately $200 million of value above our cost or about $800 million in total once the project is complete. The first step is largely done. We bought the turbines at a discount because they were located on the other side of the world in the Philippines and had to be disassembled for shipping. They are no longer in the Philippines. Title has transferred, and they are on their way to the United States. And we expect refurbishment by Siemens to begin in the coming months as they bring it up to new spec. The second step, the permits and entitlements is being finalized, the air permit, the land, the water, the pipeline capacity and the interconnection agreement. Once those 2 steps are complete, with the equipment here and the interconnection agreement in hand, we believe the project has the potential to be worth roughly $400 million more than its total cost. The third step is the contracts. We are negotiating them now, and we are targeting early 2027. Long-term contracts can add substantial value and make the balance of the project easier and cheaper to refinance. The fourth step is commercial operation in the second half of 2028. A running contracted plant is worth more than one under construction for obvious reasons. What these steps are ultimately worth depends on 2 things we don't fully control, how much margin is in the contracts we sign and what the market pays for a contracted stream of cash flow when we get there, which moves with interest rates and prevailing market conditions. The second way to look at Turtle Creek is what buyers have actually paid for assets like this. In June, TransAlta paid about $1 billion for 318 megawatts of new fully contracted gas peakers near Denver under tolling agreements of 25 years or more with investment-grade cooperatives. These are different assets with different contracts sold at different times and transaction outcomes can vary materially, but it is a recent public price for gas generation under long-term utility contracts, which is what we are building and an example of what may be achievable in the current market. Obviously, there are many factors that will impact the long-term value of our project, but I want you to understand what we see, a project we believe the market values little today, and we believe can be worth substantially more in roughly 24 months. Our fifth and final topic is financing Turtle Creek. In September, we entered into a $600 million senior secured construction bridge term loan facility with a term out option, of which $550 million was funding at closing. The financing funds a significant portion of the project. We are also finalizing a $75 million revolver. We expect to finance the balance of the capital before Turtle Creek comes online through some combination of debt, project financing, equity or the sale of part of Turtle Creek. Our stated objective has been little or no dilution to our shareholders, and that has not changed. The timing will depend in part on the outcome of our efforts to contract the plant's output. The terms of the loan are in our filings until we refinance excess cash after commercial operations goes to repay the loan and the lenders earn a minimum return. We took that structure because it funded most of the project with debt and no dilution. We may seek to refinance the loan once Turtle Creek is commercialized, meaning somewhere between signing the contracts and shortly after commercial operation. A contracted plant may be able to borrow at longer terms and lower rates than our current construction bridge term loan. Todd will review our interest expense, which includes both cash and paid-in-kind interest. We have many options. We can own Turtle Creek for decades. We could sell all or part of a contracted plan. Our attention right now is on getting Turtle Creek to a final investment decision, contracting the plant, building it and achieving the goals we described on our call today, which we believe will deliver substantial long-term value to our shareholders. With that, I'll turn it over to Todd.

Thank you, Brent, and good afternoon, everyone. Starting with our third quarter results. Electric sales for the third quarter were $92.8 million compared to $93.2 million in the prior year period, while third-party coal sales were $36.1 million compared to $51.3 million in the prior year period. Electric sales reflected a $3.6 million decline in delivered energy revenue, largely offset by higher accredited capacity revenue, which increased 21% year-over-year to $18.7 million. Total energy sales volumes declined 2%, while the average price per megawatt hour for delivered energy declined to $47.76 from $49.29, primarily reflecting increased deliveries under lower-priced prepaid forward sales contracts. Sequentially, Merom's generation increased 77% to approximately 1.4 million megawatt hours following completion of the major maintenance outage in July. Availability was 74% for the quarter and 80% for August and September. The decrease in third-party coal sales was driven by approximately 400,000 fewer tons sold to third parties, partially offset by a 10% increase in the average third-party price per ton. Sunrise also delivered fewer tons to Merom as the plant drew down its coal inventory. Sunrise produced approximately 0.9 million tons during the quarter with an average cost per ton sold of $52.17 compared to $42.74 in the prior year period. We continue to manage production around Merom's fuel needs and our existing third-party commitments. On a consolidated basis, total operating revenue was $130.3 million for the third quarter of 2026 compared to $146.6 million in the prior year period. On a sequential basis, revenue increased 28% from the second quarter, driven by higher delivered energy sales. Net loss for Q3 2026 was $4.5 million compared to net income of $23.9 million in the prior year period and a net loss of $15.2 million in the second quarter. Third quarter results include a $5.7 million loss on extinguishment of debt associated with the refinancing of our previous credit facility. Cash flow used in operations in the third quarter of 2026 was $21.8 million compared to cash flow provided from operations of $23.2 million in the prior year period. Cash flow reflected deliveries under previously prepaid power contracts and an $8.8 million increase in accounts receivable, partially offset by a $5.3 million reduction in inventory. Adjusted EBITDA, a non-GAAP measure that is reconciled in our earnings press release issued earlier today, was $17.3 million for Q3 2026 compared to $24.9 million in the prior year period and negative $2.9 million in the second quarter. The year-over-year decline primarily reflects a $9 million increase in purchase power costs during the period. These resulted from an incremental 0.1 million megawatt hours purchased and energy pricing dynamics at the time of those purchases. We invested $57.1 million in capital expenditures during the third quarter of 2026 compared to $19.4 million in the year ago period, primarily reflecting development spending associated with Turtle Creek and reliability investments at Merom. We continue to expect full year 2026 capital expenditures to remain broadly consistent with 2025 levels, excluding investments related to Turtle Creek. After incorporating the October 7 agreement into our September 30 forward sales position, the contracted forward sales position was approximately $3 billion at the segment level at quarter end and about $2.5 million on a consolidated basis, excluding intercompany coal sales. The table in this afternoon's release carries forward the one we published in October. Contracted capacity and energy revenue of $59 per megawatt hour in 2027, rising to $73 in 2030 and $75 for 2031 through 2035, with contracted capacity prices rising from $262 per megawatt day in 2027 to $478 in 2029 and about 95% of credit capacity under contract through 2035. As Brent mentioned, we sell a mix of firm and unit contingent energy. The October energy sale is unit contingent, carries a fuel price floor with recovery of qualifying excess fuel cost, required no regulatory approval and has no margin call provisions. Turning to the balance sheet and the recent steps we've taken to fund Turtle Creek, strengthen our liquidity and continued capital investment at Merom. During the quarter, we secured $600 million of construction financing for Turtle Creek through a senior secured construction bridge term loan facility and refinanced our existing debt. As a result, total bank debt rose to $550 million at September 30, 2026, from $45 million at June 30, 2026. The facility comprises $550 million funded at closing and a committed $50 million delayed draw term loan tranche, which remained undrawn at quarter end and is available subject to funding conditions. At quarter end, $329.8 million of the funded proceeds remained in restricted cash, primarily for the [ Turtle ] acquisition and related costs. Total liquidity at September 30, 2026, was $103.2 million compared to $84.2 million at June 30, 2026, and $46.4 million at September 30, 2025. At quarter end, total liquidity consisted of unrestricted cash and cash equivalents and excluded restricted cash. We are also in late-stage negotiations to secure a $75 million super priority revolving credit facility as permitted under the construction bridge term loan facility, providing approximately $55 million of additional borrowing availability after outstanding letters of credit and other commitments. A word on how the next 6 quarters will look on paper. As Brent mentioned, until Turtle Creek reaches commercial operations, reported earnings will carry the full interest expense of a plant that is not yet earning. Most of it is accrued rather than paid. The reported losses will likely widen before the plant runs. Cash interest is 3.5% on the drawn balance, about $19.3 million a year prior to funding the delayed draw term loan. We will report both, and we would encourage you to model cash. Over the next few quarters, we would point to 4 things: Merom's hours and availability, additional contract announcements, Turtle Creek equipment arriving at ports in New Orleans and Charleston before being transported to Siemens facilities in December and regulatory approval of our previously announced utility contract expected later this month. For those building a model, this afternoon's release includes contracted revenue by delivery year, Merom's trailing fixed cost and maintenance capital and the loan's cash interest terms. With that, I'll turn it over to the operator to begin the Q&A session. Thank you.

[Operator Instructions] One moment for our first question that comes from Matthew Key with Texas Capital.

You mentioned that you're seeing a larger pool of counterparties for Turtle Creek from an offtake perspective. I was curious, do you view like an investment-grade utility as the ideal counterparty as you kind of work through this process? Or does this kind of just come down to taking the best deal in terms of economics?

Well, look, we're always looking for the best deal. It comes down to a question of balancing price the customer is willing to pay and credit risk of that potential customer. I think one of the things we're very proud of today is we have pretty much all of our contracts or the majority of our contracts by far are with investment-grade utilities. And so those have just been very reliable contracts for us. We'll see what the market brings on this. I think the point we want to make is because it's gas, it's just a wider universe of potential customers.

Got it. That's helpful. And I think you mentioned that offtake agreement could potentially include an arrangement where the customer bears the cost of gas. Could you maybe just talk a little bit more about that, how that could potentially work? Do you think most of the counterparties that you've been talking with, would they be willing to explore a structure like that?

Yes. I mean we -- again, these are assets that sell 2 primary products, right? You sell capacity and you sell energy. This is a peaking plant. So capacity is the larger portion of its income. But energy is certainly has value as well. Instead of us dispatching the plant and buying gas on a daily basis, we kind of contemplate tolling the unit where essentially the counterparty rents the unit from us and they tell us when to turn it on and when to turn it off and they provide the fuel as such. And so it's just a less risky way to operate a plant. We could have separate customers for the capacity piece and for the tolling arrangement or it could be one customer that contracts for both pieces. So we'll see what comes out of our marketing efforts.

Our next question is from Nick Giles with B. Riley Securities.

Brent, you kind of walked through several buckets of ways that Merom could -- overall Merom value as you see it. And I was hoping you could go back to those and kind of walk us through which one you consider most conservative. I was trying to capture what you referenced, especially on the commercial side, but would just be helpful to go through kind of what your assumptions were there.

Yes. Again, we were talking about not the value of Merom, but the value of Turtle Creek. And so essentially, what our goal is there is to take an $800 million investment and turn it into $1.6 billion of value over a 24-month roughly period. And so we kind of outlined 2 different ways you can kind of look at that. One is there's 4 steps to the process, right? We acquired equipment that had some hair on it, right? So we got it at a discount. It was located, partially assembled overseas, had never been run. And so we had to get it disassembled and get it exported. That has now happened, right? We have -- the equipment has been disassembled. It's been exported and it's headed this way. And we have taken title to that equipment. It's on its way to Siemens U.S.A. It should be hitting U.S. shores prior to year-end. And we think that adds tremendous value because we've -- at that point, that equipment could be used by anybody, right? The second step is getting the permits and entitlements for the property, right, whether our air permit is now filed. It's been -- I think we filed that back in September. We have land rights. We have water rights. We have pipeline right-of-way rights. And we are finalizing the GIA. The study is done. We know the cost of it. We just have a contract that needs to be signed with MISO. So all those permits add, we think, another potential $200 million of value to the project. And again, all of this is very rough numbers, but we just kind of want to let the market see how we think about it, right? And then contracts, right? We are in the middle of discussions with counterparties as we speak. And we've had a lot of success contracting this year with 3 significant contracts that were signed in March, May and October, each one priced higher than the next. And that was for coal, right? So the thing we're trying to point to here is that this is gas. We expect it to price higher yet. And there's more counterparties to kind of create that competitive tension necessary to get the contract terms that we're looking for. We hope to finalize the contracts in early 2027. And then the last step is assembling the plant, right, which we think could add another $200 million of value approximately. We're still on schedule to complete that in the last half of 2028. So how do we get from $800 million of value to $1.6 billion? We think there are steps -- these are 4 basic steps along the way, and we are nearly complete with 2 of those steps. So that's just kind of how our back of the envelope, how we kind of view it. And then the other way to look at it is you have the TransAlta agreement, right? And that is a public mark that was -- I think the API was signed in June. I'm not sure that deal has closed yet. But it shows the market another mark on value, right, which kind of we think emphasizes -- you can look at that, look at the price they paid, price per kilowatt or you can look at it as look at the multiple they paid of EBITDA for that project. And that will give you kind of a range, and we think the value that we came to is -- well, it was just an indicator that we kind of used to say, yes, this is approximately right. And again, markets change. These are different deals done at different times of the year. The market is emotional and changes its description of value all the time. We're not trying to say this is exactly what's going to happen. We're just trying to give the market an idea of what we're trying to accomplish. And again, I think we've -- we're kind of rounding third on a couple of these steps. And so I think we've created a fair amount of value today.

That's super helpful and makes sense. I guess there's a lot of time for this value to still be unlocked as Turtle Creek, I misspoke earlier, is further derisked. But if we think down the road and you don't feel that Turtle Creek's full value is being reflected in the equity, I mean, would you consider spinning the asset out or just a different structure, maybe where the asset wouldn't be burdened, if you will, by Merom?

Yes, certainly. It's -- we will -- right now, we're focused on executing the 4 steps that we discussed. But along the way, the market will either value this at full value or somebody else will, right? And that means that we need to sell off a piece of it or sell off all of it to maximize value for our shareholders. Those are certainly options that are on the table.

Our next question is from Jake Sekelsky with Alliance Global Partners.

On the turbine delivery, you mentioned they're on their way State side. Can you just touch on what that refurbishment process looks like once they're at port? I mean, is there anything as far as that process goes that might come as a surprise on delivery, whether it's positive or negative?

Well, look, these were turbines that were built in the U.S., taken overseas 12 years ago, partially assembled, never hooked up to power, never hooked up to gas and sat in the building. We've -- Siemens inspected them, gave us a clean bill of health, a good report as far as they can do with an on-site inspection. We're bringing this equipment back to Siemens USA. They will inspect it. And look, there's been some upgrades to the plants over the last 12 years. So they will bring it up to new spec. And so again, I don't -- we struggle to envision what could be wrong with the plant that's never been run. But that's why Siemens USA is going to go through it and make sure that everything is in tiptop shape before it gets shipped out to our site and for assembly.

Got it. Okay. And then just can you provide a bit of color on the contracting strategy for Turtle Creek. Should we expect a similar layering type approach to what we saw at Merom? Or are you guys looking at something different?

Well, it's smaller than Merom. So it remains to be seen. Ultimately, we got to give the customer what they want. But Again, we saw a very large data center get announced 3 weeks ago in Indiana. Market intelligence tells us that there is a good chance that we're going to see some more announcements throughout this year or maybe into early next year. I know there's a lot of headlines that politics has changed and there's going to be all these restrictions on data centers. And that may or may not be true. But what we see that encourages us is that the hyperscalers are announcing larger CapEx budgets and there's less places for them to go with that money. So it's funneling -- we feel it's funneling more projects to the state of Indiana, which is say, welcome, and we're open for business. We think that has led to -- there's a data center that's broken ground contiguous to our power plant. Now we sell in front of the meter. So to us, any project in the state is a good project. The one next to us could help our marginal -- our locational marginal price or our basis differential just having that demand out at the site versus somewhere else in the state. So we're encouraged by that development. And man, I can tell you, those guys are making huge progress in a very short order. So to us, we read the headlines too, but I think the point that the market misses that is, hey, if you can't build in Texas or if you can't build in Virginia or if you can't build in some other state, those dollars then get funneled to the states that are saying, welcome. And right now, that's Indiana, and that's -- we think that's driving a lot of business towards us. We're super optimistic about this project. And again, I think we went out of our way on this call to try to outline to everybody the scope and scale of what we're attempting to do.

Our next question is from Jeff Grampp with Northland Capital Markets.

Brent, if memory serves, I think the original plan for Turtle Creek was for at least the lion's share of the economics to be based on really capacity only. It seems like you guys are directionally seemingly growing conviction that there's some pretty good power economics driving some value there as well. Would you say that's kind of become a little bit of a base case expectation at this point that there will be some degree of power energy sales as well for Turtle Creek? Or is it a bit early to make that conclusion definitively?

Yes. Look, I mean, one of the great things that's happened this year is both the value of capacity and the value of energy have improved significantly over the course of the year. I mean we've seen not just capacity prices move up substantially, but we've seen energy prices also jump say, 20% or more since January. And so what does that mean? That means all assets are being called to run more, right? We're seeing it at Merom being called to run more hours and the stark spreads look very good for gas, particularly at the relatively low gas prices and relatively high energy prices that's telling these plants to run more. And even in the tolling agreement, the counterparty is looking at that and saying, how much can I get this plant to run and what is the value of that energy is going to produce. I think we wanted to outline that we're looking at a tolling structure just to -- again, we're very much in how do we get the best deal for taking on the least risk. And so that's the structure we're kind of headed down today, and that's what we're asking the market. And I think we're going to have several interested counterparties in those types of structures.

That's great. I appreciate those details. For my follow-up, on the path to FID in Turtle Creek here, it sounds like the engineering and construction contract and the interconnection agreement are kind of the 2 remaining bogeys. To the extent those slip into '27, does that put the second half '28 time line at risk here? Or I understand the shipping delays weren't that impactful to the time line, but do any of these moving pieces give you some heartburn about the second half '28 time line? Or is that still a pretty high conviction target?

It's still a pretty high conviction target.

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

This is [ Gujath ] here on for Julien. Congrats on the quarter and all the updates. Just a quick one from me. I think you alluded to during your prepared remarks about 80% availability on the Merom side in August and September. Obviously, you have a contracted sales book for next year on the energy side. But do you think there's a potential for you to run the plant at higher capacity factor where you could sell even more than what's in your contracted book? Or just if you could share any color on just the utilization from it, that would be great.

Yes. We put in our sales table, our target is 5.2 million megawatt hours. And it's higher than we've run in the past. And that's based on 2 things. One, the spark spreads are higher, right? Energy prices are higher. So the plant is being called for to run more than in years in the past. The second thing is that we are putting a lot of investment, time and effort in people, right? We talked about people, plant and process. And I think we're making improvements on all those fronts. And I think this quarter was the first time you got to see some of those results. July's availability wasn't quite as good because we still had the plant down in maintenance, but the other 2 months ran at 80%. I think industry average for a coal plant is something like 67%. So we're cautiously optimistic about those results. And yes, I think, again, we've put it in the sales table, 5.2% is kind of what we're trying to target going forward.

I'm going to move on to the next question, please. It comes from Nick Giles with B. Riley Securities.

I just wanted to ask about the cost side at Merom and just as it relates to Sunrise, I think costs have been a little higher this year. And so I was hoping you could touch on ways that you could reduce costs on the mining side or what kind of alternatives you might have just to expand margins at Merom?

Yes. I think in the third quarter, both our customers and our own needs just weren't as great, right? Coal inventory levels were high, shipments back down. We slowed down production to some degree, all of which kind of hurts your cost structure. Next year, the plant is being called on a lot. So production will need to be robust at Sunrise to feed the plant plus meet its third-party obligations. Our sales price does increase next year. And so that should help margins at Sunrise. And we typically think of Sunrise as providing fuel for Merom to keep that cost structure in check. So what we're encouraged by in the company is pricing for all of our products steps up next year and materially on the power side of the business, right? Capacity and energy combined this year were $46. Next year, it's at $59. That's a significant price increase. We also see pricing increases on the coal, and we're expecting higher volumes for the energy piece of the business next year. So for all those reasons, we're encouraged by what's the earnings potential for the company next year.

Got it. And then just a couple of clarifying ones, if I could. I think I heard you reference Merom CapEx would be flat next year, but I wanted to clarify that. And then are there any prepaid forwards left in the book to roll off just as we kind of model the bridge from EBITDA to cash flow?

Yes. Thanks, Nick. It's Todd. Yes, I think CapEx across the platform is relatively flat next year is what we're expecting. And then we do have prepaid forwards that take us through the first half of the year, and then there will be none in the second half of the year currently.

Thank you, ladies and gentlemen. This will conclude our Q&A session and conference for today. We want to thank everyone for participating. You may now disconnect.