Hallador Energy Q3 2026 Earnings Call Transcript

Hallador Energy (NASDAQ:HNRG) reported third-quarter financial results on Monday. The transcript from the company’s third-quarter earnings call has been provided below.

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Summary

Hallador Energy highlighted strong operational results from Merom, generating over 1.4 million megawatt-hours despite maintenance, and significant capacity sales priced at a record high.

The company is advancing the Turtle Creek project, targeting to double its value from $800 million to $1.6 billion within 24 months, focusing on final investment decisions and securing long-term contracts.

Q3 2026 saw a net loss of $4.5 million, influenced by a $5.7 million debt extinguishment loss, with revenue at $130.3 million, a decrease from the previous year.

Merom’s output is heavily contracted through 2035 with investment-grade utilities, providing strong revenue visibility, while the company invests in AI tools to enhance plant reliability.

Hallador secured $600 million in construction financing for Turtle Creek and plans to use a mix of debt and possibly equity for future funding, aiming to avoid shareholder dilution.

Management expressed optimism about future growth driven by rising energy prices and increased demand from data centers, particularly in Indiana, positioning Turtle Creek as a critical future asset.

Full Transcript

OPERATOR

All participants are in listen-only mode. A question-and-answer session will follow the prepared remarks. This call is being recorded. I will now turn the call over to Sean Manchuri with Elevate IR. Please proceed.

Sean Manchuri (Investor Relations)

Thank you, and good afternoon, everyone. We appreciate you joining us to discuss our third quarter 2026 results. With me today are Brent K Bilsland, Chairman and Chief Executive Officer, and Marjorie Hargrave, 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 Energy 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 Energy 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 Chief Executive Officer Brent K Bilsland.

Brent K Bilsland (President and CEO)

Thank you, Sean, and good afternoon. Before we get into the details, there are three points from the quarter I want to highlight. First, Merom generated more than 1.4 million megawatt-hours with one unit in 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 five 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 one 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 three 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 it’s 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 half a 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 two-thirds 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 table’s 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, a quarter as firm, and a quarter as merchant. Unit-contingent means if a 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 owing 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 six 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 zero 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 conceded 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-clouds, 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 or carry a parent guarantee from the utility, and the utility’s 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 hyperscalers 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 backlogged 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 buildout faces headwinds in this country. States such as Texas and Virginia and others have slowed or paused their data center buildout, 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 four times 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 risks. 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 two 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 about 24 months. We think about value creation in four: 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 two steps are complete, with the equipment here and the interconnection agreement in hand, we believe the project has a 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 two 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 a billion dollars 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 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 can sell all or part of a contracted plant. 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.

Marjorie Hargrave (Chief Financial Officer)

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. Partially, 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 purchased 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 7th agreement into our September 30th forward sales position, the contracted forward sales position was approximately $3 billion at the segment level at quarter end and about $2.5 billion 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 accredited 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 continue 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 turbine acquisition and related costs. Full 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 superpriority 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 six 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 four 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

Thank you. And as a reminder, to ask a question, simply press star-1-1 to get in the queue and wait for your name to be announced. To remove yourself, press star-1-1 again. One moment for our first question that comes from Matthew Key with Texas Capital. Please proceed.

Matthew Key (Analyst)

Good afternoon, and thanks for taking my questions. You mentioned that you’re seeing a larger pool of counterparties for Turtle Creek. From an offtake perspective, I was curious, do you view an investment-grade utility as the ideal counterparty as you kind of work through this process, or does this just come down to taking the best deal in terms of economics?

Brent K Bilsland (President and CEO)

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, 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.

Matthew Key (Analyst)

Got it. No, 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?

Brent K Bilsland (President and CEO)

Yes. Again, these are assets that sell two 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 certainly has value as well. Instead of us dispatching the plant and buying gas on a daily basis, we 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.

Matthew Key (Analyst)

Great. Well, I’ll jump back in the queue, but I appreciate the time.

Brent K Bilsland (President and CEO)

Thank you, Matthew.

OPERATOR

Thank you. Our next question is from Nick Giles with B. Riley Securities. Please proceed.

Nick Giles (Analyst)

Yeah, thanks, operator. Good afternoon, guys. Brent, you kind of walked through several buckets of ways that Merom could, you know, of 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 for kind of what your assumptions were there. Thanks.

Brent K Bilsland (President and CEO)

Yeah, 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 roughly 24-month period. So we kind of outlined two different ways you can look at that. One is there’s four 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. 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 USA. It should be hitting U.S. shores prior to year end. And we think that adds tremendous value because at that point that equipment could be used by anybody. The second step is getting the permits and entitlements for the property. Our air permit is now filed — 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 this is very rough numbers, but we just kind of want to let the market see how we think about it. Then contracts. We are in the middle of discussions with counterparties as we speak. We’ve had a lot of success contracting this year with three significant contracts that were signed in March, May, and October — each one priced higher than the next. That was for coal. 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 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, 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 four basic steps along the way — and we are nearly complete with two of those steps. So that’s just kind of our back of the envelope — how we view it.

And then the other way to look at it is you have the TransAlta agreement, and that is a public mark. 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, which, we think, emphasizes — you can look at that, look at the price they paid, price per kilowatt, or you can look at it as the multiple they paid of EBITDA for that project, and that will give you a kind of range. And we think the value that we came to was just an indicator that we used to say, yeah, this is approximately right.

And again, markets change. These are different deals done at different times of the year. The market is emotional; it 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’re rounding third on a couple of these steps, and so I think we’ve created a fair amount of value today.

Nick Giles (Analyst)

Thanks for that, Brent. 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 de-risked. But if we think down the road and you don’t feel that Turtle Creek’s full value is being reflected in the equity, 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?

Brent K Bilsland (President and CEO)

Yeah, certainly. Right now we’re focused on executing the four steps that we discussed. But along the way, the market will either value this at full value or somebody else will. If 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.

Nick Giles (Analyst)

Good to hear. Okay, I’ll jump back into queue, but appreciate the update and continue. Best of luck.

Brent K Bilsland (President and CEO)

Thanks, Nick.

OPERATOR

Thank you. Our next question is from Jake Sekelski with Alliance Global Partners. Please proceed.

Jake Sekelski (Analyst)

Hi, Brent and Todd. Thanks for taking my questions. On the turbine delivery, you mentioned they’re on their way stateside. 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?

Brent K Bilsland (President and CEO)

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 a building. Siemens inspected them and 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 specs.

We struggle to envision what could be wrong with a 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 tip-top shape before it gets shipped out to our site for assembly.

Jake Sekelski (Analyst)

Got it. Okay. And then 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?

Brent K Bilsland (President and CEO)

Well, it’s smaller than Merom, so it remains to be seen. Ultimately, we have to give the customer what they want. But again, we saw a very large data center get announced three 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 — politics has changed, there are 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 fewer 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 saying, “Welcome, we’re open for business.” We think that has led to 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 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 very short order.

So we read the headlines, too. But I think the point that the market misses 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 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.

Thanks, Jake.

Jake Sekelski (Analyst)

Makes sense. Thanks again. I’ll hop back in queue.

OPERATOR

Thank you. Our next question is from Jeff Gramp with Northland Capital Markets. Please proceed.

Jeff Gramp (Analyst)

Jeff, thanks for the time, 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 growing conviction that there’s some pretty good power economics driving some value there as well. Would you say that’s 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?

Brent K Bilsland (President and CEO)

Yeah, look, 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. 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. We’re seeing it at Merom — it’s being called to run more hours. And the spark 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 a tolling agreement, the counterparty is looking at that and saying, how much can I get this plant to run and what is the value that energy is going to produce? I think we wanted to outline that we’re looking at a tolling structure — 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 headed down today. And I think we’re going to have several interested counterparties in those types of structures.

Jeff Gramp (Analyst)

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

Brent K Bilsland (President and CEO)

It’s still a pretty high-conviction target.

Jeff Gramp (Analyst)

Okay, I’ll leave it there. Thanks.

Brent K Bilsland (President and CEO)

Thank you, Joe.

OPERATOR

Thank you. Our next question comes from Julian Dumoulin Smith with Jefferies. Please proceed.

Gujarat (Analyst)

Hey guys, thanks for taking the question. This is Gujarat here on for Julian. 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 contracted sales 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 if you could share any color on the utilization from it, that’d be great. Thanks.

Brent K Bilsland (President and CEO)

Yes. We put in our sales table our target is 5.2 million megawatt-hours. That’s higher than we’ve run in the past, and it’s based on two things. One, the spark spreads are higher — energy prices are higher — so the plant is being called to run more than in years past. The second thing is that we are putting a lot of investment, time, effort, and people — we talked about people, plant, and process — and I think we’re making improvements on all those fronts.

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 two 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, yeah, I think again we’ve put it in the sales table — 5.2 is kind of what we’re trying to target going forward.

OPERATOR

I’m going to move on to the next question. One moment please. It comes from Nick Giles with B. Riley Securities. Please proceed.

Nick Giles (Analyst)

Thanks for taking my follow-up. 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. Thank you.

Brent K Bilsland (President and CEO)

Yeah, I think, you know, in the third quarter, both our customers and our own needs just weren’t as great. Coal inventory levels were high, shipments backed down. We slowed down production to some degree. All of which kind of hurts your cost structure. Next year, the plant’s 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. 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, you know, pricing for all of our products steps up next year and materially on the power side of the business.

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 earning potential for the company next year.

Nick Giles (Analyst)

All right, thanks for that, Brent. And just a couple clarifying ones, if I could. I think I heard you reference Merom Capex would be flat next year, but 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? Thank you.

R. Todd Davis (SVP & CAO)

Yeah, thanks, Nick. It’s Todd. Yeah, 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’ll be none in the second half of the year currently.

Nick Giles (Analyst)

Okay, perfect. Thanks again, guys. I really appreciate it.

OPERATOR

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

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