Hello, everyone, and welcome to the Hallador Energy third quarter 2023 earnings call. My name is Emily, and I'll be coordinating your call today. After the presentation, there will be the opportunity for any questions, which you can ask by pressing star, followed by the number one on your telephone keypads. I will now turn the call over to our host, Rebecca Palumbo. Please go ahead. Thank you, Emily, thank you everybody for joining us today. Yesterday afternoon, we released our third quarter 2023 financial and operating results on Form 10-Q, and that is now posted on our website. With me today on this call is Brent Bilsland, our President and CEO, and Larry Martin, our CFO. After just the prepared remarks, we will open up the call to your questions. Before we begin, please note that the discussion today may contain certain forward-looking statements that are statements related to the future, not past events. In this context, forward-looking statements often address our expected future business and financial performance. While these forward-looking statements are based on information currently available to us, if one or more of these risks and uncertainties materialize, or if our assumptions prove incorrect, actual results may vary materially from those we projected or expected. For example, our estimates of mining costs, future sales, legislation, or regulations. In providing these remarks, we have no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise, that may be required by law. For a discussion of those risks and uncertainties that may affect our future results, please review the risk factors described from time to time in the reports we file with the SEC. As a reminder, this call is being recorded. In addition, we will have an archived webcast of this earnings call on our website. We encourage you to ask questions during the Q&A, and if you are on the webcast and would like to ask a question, you will need to dial into the conference line. That toll-free number is 1-833-470-1428, access code 224373. With that, I'll turn the call over to Larry. Thank you, Becky, and good afternoon, everyone. Before I begin, I want to define adjusted EBITDA, which we define as operating cash flow, less the effects of certain subsidiary and equity method investments, plus bank interest, less the effects of working capital changes, plus cash paid on asset retirement obligation reclamation, plus other amortization. For the quarter, Hallador incurred net income of $16.1 million, which was $0.49 basic earnings per share or $0.44 for diluted earnings per share. For the year, net income was $55 million, $1.66 per share earnings per share, $1.52 diluted earnings per share. We had adjusted EBITDA for the quarter of $35.9 million, and for the year, $105.2 million. We decreased the bank debt by $12.5 million for the quarter, $23.5 million for the year. Our funded bank debt as of September thirtieth was $61.8 million. We had letters of credit totaling $11.2 million, and our net funded bank debt was $59.2 million, which is funded or bank debt less cash. Our leverage ratio, which is defined as debt to adjusted EBITDA, was 7.1 times at September 30th. Did I say seven point? Point seven one times for the quarter. I will now return the call over to Brent to review the quarter and beyond. Thank you, Larry. First, I'd like to thank the Hallador team for their hard work and dedication on creating another successful quarter. As I have highlighted in our previous quarters, our goals of increasing profitability, increasing company liquidity, and reducing balance sheet leverage remain paramount to how we operate as a company. This quarter's results show our continued progress towards these goals. Our net income of $16.1 million for the quarter helped build on our record net income of $55 million for the first nine months. Our continued record operating cash flow of $79.5 million over the nine-month period has allowed us to invest $48.7 million in capital expenditures to improve our efficiency and reliability at both our mines and our power plant. We make continued progress on our goal of improving our balance sheet by repaying $23.5 million in debt during the first nine months of the year, $12.5 million of which was during the third quarter. This further reduced our leverage, as Larry said, to 0.71 times, while we increased liquidity to $66.4 million as of September 30th. On October 2nd, we successfully amended our credit facility with PNC Bank, which we accounted for as a debt extinguishment. This amendment is important as it extends the maturity of our credit facility into 2026. During the third quarter, high coal sales prices, coupled with large coal shipment volumes, led to record coal revenue. Our well-contracted sales book supported our revenue growth despite operational challenges, increasing our cost per ton during the quarter. We chose to relocate 57% of our coal units of production during the third quarter and into October to obtain better geologic conditions. This led to higher cost and decreased production during this time frame, but it was resulting in overall production improvements following the moves, which we expect to continue. During the quarter, we shipped 2.1 million tons of coal at an average price of $56.43 before intercompany eliminations. We produced 1.6 million tons in the quarter at $46.54 per ton before eliminations, leading to margins of $18.89 per ton during the third quarter before eliminations. We expect an average price of $54.30 per ton on the remaining tons to be shipped this year. On the power side of the business, intercompany coal sales from our coal division to our power plant division increased the average variable cost per megawatt hour to $40.03 per megawatt hour, an increase of $9.98 per megawatt hour over the prior quarter before eliminations. We set the price of coal we sell to ourselves based on third-party market indicators that we review from time to time. Cost per megawatt hour were $23.49 on a consolidated basis. As the marketing price fluctuates, we expect to see these types of variances in each side of the business. During the quarter, we produced 1.3 million megawatt hours. We are excited about the progress we are making in our forward power and sales capacity book. During the quarter, and in the time leading up to this release, our power division was successful in securing $325 million of energy and capacity sales across multiple years, as reported in our Form 10-Q filed last night. This morning, we received a signed agreement for an additional $41 million of capacity and revenue over the years 2024, 2025 and 2026, bringing this number of total sales up to $366 million. These sales are important as they create a profitable foundation for our power division over the next five years, with sufficient energy sales at... Or excuse me, with significant energy sales at $56 per MWh and capacity prices approaching $220 per MW-day. Now, we get a lot of questions concerning how an investor should think about Hallador, now that we have added a power division. To add clarity, we included a detailed section. We included a lot of detail in Section 3 of the overview of the MD&A, outlining our sales of coal, power, and capacity through 2028. At a high level, I think about our business as such: we produce 7 million tons of coal annually. Just over 4 million tons is sold to outside customers, and almost 3 million tons is sold to our power division, Hallador Power. The reference table will show that over the next five years, 54% of the coal that we plan to sell to outside parties is already committed to those parties, and 73% of these commitments are priced at an average price of $52.60 per ton. Our year-to-date cost per ton to produce coal was $43.25. The other 3 million tons assume that we will annually produce 6 million MWh at our power plant. Now, there are rules about how we price this coal to ourselves, and the accounting around this can be confusing to follow due to the internal eliminations. However, the price that is chosen for the coal that we sell ourselves only determines how much profit or loss is allocated to our coal division or our power division. Ultimately, what matters is how much profit is made at Hallador based on our cost structure. During the third quarter, our consolidated variable cost at the plant was $23.49 per MWh. As stated in previous quarters, we use our capacity sales to cover the majority of our fixed costs at the plant. We have sold, and we expect, you know, with the capacity prices that we're seeing, that to continue. We have sold approximately 27% of our future power through 2025 at $34 per megawatt hour, roughly a $10 margin based upon that cost structure. But in this past quarter, we have sold 3.3 million megawatt hours for the 2026, 2027, 2028 years at $56 per megawatt hour, which is roughly $32 per megawatt hour profit margins based on today's cost structures. These sales have us very excited about the profit potential for Hallador Power. Now, that doesn't mean there won't be operational challenge, such as the one we experienced on October second, when we had an unplanned transformer outage in one of the generators at the power plant. The transformer has since been replaced, and the event will cause us to miss a net 2-3 weeks of output from one of those two units. I want to reemphasize, I am very excited about the future of the company, especially as I look to the power sales through 2028. What we are seeing through increased pricing from our recent power PPAs, coupled with strong capacity, demand, and pricing. With the solid book of business that we are now showing and the steady supply of coal from our mines, I am incredibly pleased with the progress that we are making towards leveraging the opportunities that drove our decision to acquire the power plant. As I said at the start of my comments, I'm encouraged by the quarterly results and the continued progression of Hallador as a company. And with that, I will open up the call for questions. Before we go to questions, I want to clarify one sentence here. Our coal shipments were 2.1 million at $65.43 for the quarter, for an $18.89 per ton margin. Thank you, Larry. If you would like to ask a question, please do so now by pressing star, followed by the number one on your telephone keypad. If you change your mind and would like to be removed from the queue, please press star and then two. When preparing to ask your question, please ensure that your device and your microphone are unmuted locally. We will just pause for a second to allow the questions to come into the queue. Our first question today comes from the line of Kevin Tracey with Oberon Asset Management. Kevin, please go ahead. Your line is now open. Great. Thanks for taking my questions. The first one is just to clarify what I thought you just... I heard you say about the outage at Merom. So, in the 10-Q, there's a note where it says, "The unit isn't expected to be back into service till the second half of December." So, but I thought I heard you say that the outage was only 2-3 weeks. So I guess, was it, are we kind of missing 2.5 months or 2-3 weeks of this unit? Yeah, let me clarify that. So the unit was already scheduled to go on a scheduled outage from November 1st to December 27th. Okay. That's something that we schedule with MISO, you know, 6 months to 9 months in advance, and we bring in outside contractors to do routine maintenance on the unit. So that was planned. The unit went down basically a month early due to the transformer, and so we have sped up part of the outage work to begin some of that work that we could do in October, which means instead of the unit coming back online, it's December 27th, it'll probably come back online a week or two earlier than it was previously scheduled. Net-net, we're gonna lose this unit, 1 of the 2 units for 2-3 weeks longer than was expected and planned for. Okay. Cross your fingers the power prices are higher in December. Okay. And going forward, do you expect any impact on MISO's accreditation of the plant, you know, for purposes of future capacity revenues, or are you hoping that won't be material? Yeah, I think every time you have a forced outage... So, so accreditation is a rolling three-month or a three-year process, right? And so they're looking at your performance history during that time frame. So things that help your capacity rating are, you know, we acquired a plant that was scheduled for shutdown, so some of that maintenance was let go, and we are, you know, spending additional monies this year and next to kind of get the plant back in what I would call tip-top shape. And so where that helps you on accreditation is, you know, we're seeing higher output numbers than when we took over the plant a little over a year ago, right? So as you get newer and better and refurbished equipment on the plant, you're able to achieve, you know, higher performance. That's, that's to the good side. The bad side is every time you have a unscheduled outage, such as we had with the transformer, that counts against you in accreditation. And then I'd say thirdly, we still see MISO making tweaks and adjustment to their accreditation process. They've not finalized those rules, and so we can't ever be 100% certain what comes out of that. Do we get more accreditation? Do we get less accreditation? It's always hard to say. So all we can do, and what we have done is, as of our last accreditation, which was 800 and, I mean, it's on a seasonal basis, but I think on average, our accreditation was 860 MW. That's what we're basing our numbers on. So when we show you, "Hey, here's how much capacity we've sold as a percentage of the plant," it's based on an assumption that our accreditation is 860, but that number could go up or down based on our next accreditation from MISO. I want to emphasize on one thing Brent talked about. The being down also depends on when. If you are down in a low demand period, it doesn't count against you as much as if you were down during a high demand, say, minus 20 degrees or something like that in the winter when there's a lot of demand for electricity. So us being down in October in a mild season may not count as much against us as. And we may get more upside when we come back on in December. That's total speculation, but it is... Understood. That, that. Yeah. Odds are we're going to have colder weather in December than we had in October. Power prices theoretically would be higher... And demand So, you know, it may not be as, you know, we may be trading four mild weather weeks for two cold weather weeks. We just don't know, and we won't know till we get there. Understood. Okay. And then, so with these power sales agreements you've entered in, so you've sold about a quarter of your planned generation for the next several years. Can you talk a bit more about how high you want to go in terms of selling power forward as a percentage of your expectation? And then, how are you managing the risk there, or, you know, if the plant were to have an unplanned outage, and you've agreed to supply power, at certain prices, you know, you could find yourself long the power market. So how are you kind of managing risk when you're thinking about entering those agreements? And if you could touch on how high you're hoping to go in terms of forward sales. Yeah, good question. So far to date, everything that we have sold on the power side is plant or unit contingent, meaning that we've sold the power, and if we fail to perform, we do not have to go out and buy that power. We don't have to cover, right? We just simply are not shipping those electrons to the customer, and they either have to do without, or they have to go buy them elsewhere. But that is not on our account. So I think, you know, as excited as we are about our sales, on a risk-adjusted basis, we're extremely excited about that. Okay. We'll look to see what opportunities are for... You know, these are bilateral agreements. These are not exchange hedges, you know. On an exchange hedge, that's firm, that's a firm power sale, we would have to cover in that scenario. And so we want to make sure that we have a lot of liquidity if we do that type of hedging. And so, you know, part of our process and what we've talked about here is we want to make sure we get our balance sheet as healthy as possible, get our liquidity as high as possible, and then we'll look to the market to see if there is hedges that we want to additional hedges that we'd like to layer in. Okay. We certainly... And then on the mining cost per- Yeah. Sorry, go ahead. Yeah, I was just going to say, we certainly prefer the bilateral agreements on a risk-adjusted basis. Got it. Okay, and then on the mining cost per ton, so I think heading into this year, the hope was that we would see an improvement over 2022's $37 per ton. We've obviously seen costs rise quite a bit from there. Can you talk about kind of what went wrong versus your expectations? Was it just in general inflation or an issue with the geology? And you made some comments about, you know, improvements you're seeing from some changes you're making. Can you help set expectations on where you think your mining cost per ton will be for 2024? So on the production outlook, you know, it's pretty typical. We have seven units, seven individual production units underground. I think it's pretty typical in any given quarter for one or two of those to be struggling. What was unusual about this quarter is we had four units struggling, and, you know, we sometimes that catches you at a time that's a little out of sequence to be moving. So, you know, you fight that for a little while, and then finally, ultimately, you come to the decision of, we need to shut the unit down and move it. And there's just lost time and production... when you do that, particularly out of sequence like we did this quarter and into October. So very unusual to move four units at any given quarter, but that's what we did, and that's, you know, ultimately had an outsized factor on why our costs were the highest they've ever been in any quarter in the history of the company. So disappointed by that. All I can say is we've moved those units and, you know, I'm pleased with the productivity that I'm seeing to date out of those units. So we expect our cost structure to be better in the future. Okay. Are you willing to put out a number on where you think the cost structure will be? Can we get into the 30s again? I think that, you know, I think we will... You know, we have seen inflation, so I, I think probably in 2024, gosh, some of that's gonna depend on, you know, what the production levels are at each mine. But I, I think you'll see us back into the low 40s, upper 30s. Okay. And then on the CapEx, so your fourth quarter guidance implies that the full year CapEx will come in about $10 million than your original budget. And it looks like all of that, I guess, all of that delta from your original guide is coming from the, the coal business. Can you talk about where you think CapEx will end up kind of on a normal basis for the coal business going forward? And then, do you have any update on the effluent project at Merom, and kind of where you're thinking the CapEx budget is gonna look like next year? I'll handle the coal part, and then Brent can answer the effluent question. But for the coal plant, we just had some with our moving things around, the 57% we moved, we had some mine development we had to do, and then we had some equipment that came on- that's gonna come on at the end of the year, that we thought was gonna be in the next year. So that's our $10 million difference. Going forward, I think our plan is $35 million for CapEx for the coal plant. Do you want to talk about ELGs? Yeah, on ELGs. Okay. So the EPA has proposed a new rule that has yet to go final. So we are waiting to see where they ultimately end up, and we expect them to finalize that rule in this coming spring. And so that ultimately will decide what we do and the exact timing and compliance date to meet that rule. Our board has approved $45 million to spend on that. We still feel comfortable that will meet where we think the EPA is heading with that rule and their most stringent standard. But we'll wait to see where they end up on the final rule before we comply with that. So that is delaying the expenditure of some of those dollars until we know exactly what the EPA wants. Okay, and the last quick one here. On the last call, your latest update on your target of getting to basically zero net debt was the second quarter of next year. Is there any update to that guidance? Yeah, I think the higher cost that we experienced this quarter is gonna push that out at least a quarter and into the third quarter of 2024. Okay. All right. Thanks for answering all those. Yeah. Thank you. Our next question comes from Kenneth Pounds with Castlebury Advisory. Please go ahead, Kevin. Your line is open. Yeah, Kevin, thank you. I think you mentioned in the last call that you were looking for, you might benefit from a hot summer or, you know, surges in demand in the summer. Did you experience that with the power plant? No, we really saw a pretty mild summer. I think we had two weeks of, you know, hot weather, so we saw good pricing during that time frame. But, you know, the balance of summer was from a power pricing perspective, was fairly anemic. So we're still, you know, kind of waiting for, you know, more, you know, colder, colder days or hotter days, but we don't like 65-degree days from a business perspective. Right. On the West Coast here, there's been refineries closing. Are there some other older power plants that are in your area that might be closing that would tighten up the market, or have you seen anything like that? Yes, we did. We did just have another power plant that closed last week in MISO Zone Six, which is the zone that we're in. We think, you know, the trend continues to be, people are taking generation out of MISO that has an on switch, and replacing it with generators that do not have an on switch. As long as that trend continues, that should increase the value of capacity. It's going to create higher highs and lower lows in the power markets, right? Because renewables tend to give you electrons, not necessarily when you need them. So if we can be a generator that can provide electrons when they're needed, we think that, you know, we're gonna see some days where there's some pretty extreme high pricing. When we have an open position, such as we have today, a relatively open position, then, you know, it affords us those opportunities to take advantage of that. So we'll see what the weather brings. As you know, we continue each day to go to work to try to sell more power through bilateral agreements. You know, I think this quarter was a solid performance in that with I guess if you include the contract we drug in the door today, it was, you know, $366 million of power and capacity sales. We keep having quarters like that, I think our investors are gonna be very happy. Yeah, sure, you definitely improved earnings visibility. And I know you've made similar comments before, which sound prescient. We've had a lot of reports lately about these renewable projects being too expensive and not delivering, you know, certainly the margins that people had wanted. Finally, you said you had four of the seven units that struggled. Are some of those units maybe not gonna be too high cost if we keep seeing, you know, costs creep, you know, all over the country? Not just you guys, obviously, with inflation and fuel and so forth. Yeah, I thought it was interesting. There's been several mining companies that have reported before us, and it seemed like everybody had a tough operational third quarter. I'm not really sure why that is. I don't know if it was something about the, you know, a lot of humidity that came out of the mines as it cooled down, or if it was just coincidence. But certainly everybody is seeing cost pressure due to inflation, but I really think the majority of what we had going on this particular quarter and into October was geologic and specific to our mines. And I think that we have solved that problem. And, you know, I'm sorry that the quarter wasn't better from an operational cost point of view, but I hope, I think we've fixed the problem. Great. Well, thank you. Thank you so much, and keep up the good work. Thank you very much. Our next question comes from Jason Lustig with J. Goldman. Please go ahead, Jason, your line is open. Hey, thanks for taking the question. Just wanted to say thank you for increasing the disclosure in the contract table, really helps. I think as another caller said, just better understand the long-term economics of the company. So appreciate that. You know, as I have thought more about this table, I think we're getting a sense for what the future revenues of the company can look like, the three different revenue streams. We have a reasonable sense of the coal costs per ton, the fixed costs we've talked about in the past at the, at the plant. One thing that I'm struggling a lot with and would appreciate trying to better understand is the variable costs per megawatt hour, excluding fuel at the plant, and how we should think about that over time. Well, look, I mean, fuel is the majority of it. I think we've come out and said that, you know, during the quarter, on a consolidated basis, variable costs, including fuel and non-fuel, was $23.50 per MWh. So, you know, I don't think at this time we plan to break out what our non-fuel expense is. Quite frankly, I think we've got enough numbers that, you know, our goal is to not confuse everyone. Our goal is to create as much clarity as possible, and that's why we spent a lot of time on that table I referenced in an effort to try to get everyone to understand, right? Because it gets very confusing when you start pricing coal to yourself and you have these company intercompany eliminations, which is all GAAP. It's all, it's all, you know, the way it's supposed to be, but we're trying to clarify that, hey, at the bottom line, there's extreme... It's just a great earnings potential at the power plant. And, you know, we hope everybody gets as excited about that as we are, particularly when, you know, our most recent pricing, particularly on a risk-free basis, since it's unit contingent, it is quite profitable. And so, anyhow, I appreciate your compliments on that. We're probably not, on this call, gonna get into what our non-fuel costs are at this time. Okay, okay. I appreciate that. If I flip to the coal operations segment of the 10-Q, I see that there's $37 million in sales to the Merom plant that are eliminated in consolidation. And I would love to try and triangulate and better understand how that, how I can reconcile that number with the $40.03 per megawatt hour cost at Merom, variable cost at Merom, and the 23,049 consolidated number. And maybe that can get us most of the way there for those who are on the outside and still confused. Well, I'm not 100% sure I understand that question. I'm trying to... I just, you know, we can do our own math, I guess, on the outside to triangulate any confusion. But, I am trying to figure out how much, I guess, what was the cost or the price of the coal that was transferred, and was it the right number? Is it 500,000 tons? I think I saw somewhere else in the 10-Q. Is there some other number that I should be using for this quarter? And I can just... No. So I think... I just want to make sure I'm looking at the right numbers. So everything's in, and I'll give you... I mean, I'm not, you guys can do the math, but here's the numbers. We sold coal to ourselves for $75, which is in the Q, so we have to eliminate that. Mm-hmm. And then our costs were 40-some doll- I can't remember off the top of my head where they're at in the Q, but then our costs for the quarter were $46, I think. So that, that has to be, that profit has to be eliminated as you sell the coal to yourself. Now, we did burn, but it, it's not just what we sold in sales, it's what we actually burned. You know, there's some sitting in inventory that got eliminated as well. Right. Okay. All right. I think that gets me most of the way there. Thank you. Great. Okay, thanks. All right. Thank you for your questions. Before we take our next question, as a reminder, if you would like to ask a question today, please do so now by pressing star, followed by the number one on your telephone keypads. Our next question comes from Tom Kerr with Zacks Investment Research. Tom, please go ahead. Your line is open. Well, good morning, guys, or good afternoon. I think most of my questions were just covered. A couple quick ones. As you guys continue to generate more free cash flow, re-refresh my memory if there's any restrictions on returning capital to shareholders through dividends, share buybacks, et cetera. No, at our current leverage ratio, we have no restrictions. Okay, great. And then lastly, you guys have indicated in the past that you may be looking for other power plants for acquisitions to add to the, that side of the business. Does that still look good? Is that still a plan or any opportunities out there you can mention? Well, nothing we can list specifically by name. We are always looking, and we think there's, you know, Hallador is in a unique spot to potentially take advantage of those opportunities. So, certainly, we are looking. Okay, great. That's all I have for today. Thanks. All right, thank you. Thanks, Tom. Our next question comes from Lucas Pipes with B. Riley Securities. Please go ahead. Your line is open. Thank you very much, operator. Just a few quick ones from me. First, Brent, in terms of struggling, on the coal side, what exactly is meant by that? What happened? I think we just, you know, you have units that run into bad roof. You know, it could be, could be that you've got presence of water or sandstone coming in close contact, or close location to the coal. And, you know, when we get... That's sometimes you can fight through that and get to the other side of it, and other times you have to back up, move over. Sometimes you back up, move over, back up, move over a second time, and then, you know, there comes a point, where you just say, "You know what? I'm gonna, I'm gonna move, to, to a different portion of the mine and tackle, tackle this from a different angle or different, point of view." You know, moving over and attacking it again, that's pretty common. That happens. Major moves to the, you know, to a different area, that's pretty uncommon, and particularly for four units in one particular quarter. So I, you know, I think we wanna say that it was significant, it was unusual, and we think that that's behind us. Were all those four units working in close proximity when they encountered these difficulties? No. The areas that you moved out of, are you gonna move back towards them in due course, or would you say, you know, for the foreseeable future, it was just too tough, you don't wanna go back there? Yeah, I mean, sometimes you just move around to the other side of it, right? There's a, you know, there could be a good area of coal that can be a year or two of good mining, and you just need to access that from a different location. So it's not, you know, I don't want you, to lead you to believe that we're abandoning large portions of our reserve. That's not the case at all. We are just attacking it from a different point of view. Got it. Okay, that's helpful. Thank you for that. And then I wanna go back to your comments earlier on hedging versus bilateral agreements, and it sounded like there are certain advantages on these bilateral agreements. And is, does it come down to force majeure provisions? Is that really the difference? No, I mean, it's just that it's pretty common to have either firm sales or unit contingent sales. And, you know, a bilateral agreement with a particular customer is a very bespoke agreement. And, you know, it can have, I would almost argue that no two agreements like that are exactly the same. Whereas, hey, if I'm just jumping on, you know, ICE and buying or selling a power contract, that's a very, you know, cookie-cutter fixed agreement. You know, it's different. And it, you know, it takes on more risk, right? You can get a margin call if you're on ICE. I can't get a margin call from my customers. That's right. We have unit contingent powers. So from a risk perspective, I think we've put ourselves in a really good, you know, what we say is a good foundation of business. I don't know that we can sell all of our power under that particular format, so we'll see. All we're saying is that we had great success this particular quarter, and we've got a great team that's out trying to, you know, get in situations that's both good for our customer and good for ourselves. And, Lucas, to expand on that a little bit- Yeah, totally. Think of it as... I mean, we say unit contingent, but we have guaranteed, you know, a certain percentage for the year. So even if the unit goes down, we don't have to deliver on a unit contingent basis. And, you know, power could be very high that day, and we don't get penalized. But then some of that, depending on the percentage, we may make up later at our contracted price. So you said force majeure. It's not really force majeure, but kinda. Got it. Got it. So, the kind of the legal term would be there, kind of, I think you said unit contingent, right? Correct. That's helpful. Thank you. And then, I really appreciate the disclosures. Quick question there on page 18 of the Q. Contracted power revenue, that line shows 2024, $98.05 million. That's pretty clear. The item immediately underneath it, how is that derived exactly? Can you walk me through that, the $43.34, the revenue per megawatt hour? I don't... It clearly doesn't assume the $6 million, so I kind of struggled a bit to back into that. 78% of 6 million. Lucas, that is the actual... That's contract, what we have contracted for the year, which is 78% of 6 million? Mm-hmm. Got it. Got it. Okay, so it's not based on the 6 million, it's based on, you're making the assumption you're running it, you said 78% of the 6 million? Well, it's what we have. We don't have 6 million contracts, but we have 6 million we can provide. So the 98 million is what we have contracted. Yep. For total, that's total capacity and energy. Correct. Correct. And the line underneath it, the 43.34, what is that based on? It's how much revenue we're gonna get on our contracted megawatts. But you have only $1.6 million contracted, no? But that includes capacity and power. Got it. Okay. I think what we're showing here is- $4,365 divided by 78% of $6,000,932 plus $34. Yeah, maybe we can take that offline, but I appreciate it. I think I know where this is going, but maybe one quick follow-up. You have only $1.6 million of output contracted, right? Correct. And so, I mean, the capacity payments, you can still... You have capacity payments, but you can still generate revenue on top of that, though? Absolutely. Okay, I appreciate that. So we have... Thank you. We have 4.4 million megawatt hours of power that we can still contract. Okay. For us, yeah. Yeah, makes sense. Makes sense. I really appreciate all the color and, again, best of luck. Thank you. All right. Thank you, Lucas. Our next question comes from Roger Ziegler, who is a private investor. Roger, please go ahead. Hi. Congrats on a good strong quarter despite some obstacle, guys. My question is I've not had a chance to delve into the section three. You said it's the, it's related to power in general, this exciting new market. Am I reading the release that just posted the table, the one of the tables that in 2024, you've got 27% of your power priced? Is that correct, from the basic, the non-GAAP table that was provided in- At $34? Yes. Yes. Yes, that's correct. So you've got 83% left to potentially, you know, there'd be some windfall times in there if possible, right? When you get some extremes either way, as you said, that's pretty exciting. That'd be 77%. Yeah. So basically, what... Seventy-three We've got... Seventy-three percent. Yeah. We've got 27%, let's just call it fourths, round math. We've got a fourth price, and we've got another two-thirds or three-fourths that we're open to. You know, we bid into the market every day, and prices can be high, and prices can be low, and prices can be so low that we take the unit offline. But, you know, we think we're heading into, we're heading into winter, and that typically, historically, has been some of the better pricing. So, you know, we'll see what December, January, and February bring. But also, we have... Are you able to.... 78% of our capacity. We have 78% of our capacity sold for next year, which, you know, if we sell 100% of our capacity, we think that will cover the majority of our fixed costs. Correct. Okay, and a real general question, you may or may not be willing to answer, but, you know, pick kind of a basic high-level question: Is the— Are you finding it's very strong correlation to the nat gas market for power as it is with coal? Oh, yes. I mean, there's a lot of gas... Price point. Generation in MISO, and so if gas prices are cheap, those units, those gas units can produce cheap power, and we have to compete against that to a certain point, because, you know, once load exceeds gas generation, then coal is gonna compete against coal. Or if gas prices go high, as they did last, you know, in 2022, then you'll see coal potentially dispatched in front of gas, and gas will take the upper end of the market. But, you know, pricing today on gas is pretty cheap. Right. Yeah, the coal-to-gas switching thing and vice versa, right? It's always in play, right? So and so... Always in play. One last question on this topic, perhaps. You know, should we, you know, regarding again, the power market, are you mostly correlated to the Chicago hub, MISO hub, and even the nat gas in some way? Or is it more of a—like, this summer with record heat throughout Texas in the south for upwards of a month, were you able to capitalize on that this past summer, or is it more of a regional, you know, say, Indiana... No, it's more... Through Chicago? Should we think of it in that, those terms? Yeah, it's definitely more important what the weather is, Indiana through Chicago. The gas price that's closest to us matters the most, which in that case, you know, Chicago Citygate is one marker that we look at for sure. So you weathered a bad summer that way. Chicago was as mild as it's been for forever, right? And you were right south of you. You had some... Correct. Heat. So let's hope for another- Correct. Right? I mean, Yeah. Yeah, I mean, we would love for the power plant- I'm struggling with gas. Yeah, we would've loved for the power plant. Hell, yeah. So I... But, yeah. Just hoping for a frigid winter, you know. Well, I think, look, we are very encouraged in that there is a lot of new industrial demand showing up in the Midwest. You know, Europe has had basically an energy crisis since the Russian invasion of Ukraine, and that's causing a lot of re-onshoring of industry. I was with politicians yesterday, who more than one said: "You know, look, Indiana has a great business climate. We're not sure if we have enough people, and we're not sure if we have enough power." And so Hallador being long power likes to be in that scenario. We like where we're at. There's gonna be some volatility to our earnings because we do have a large open power position, and that is subject to market movements. It'd be great, and you know, there's a high end, and there's a low end, but I think by and large, on average, we'll do really, really well. That's why we like the base of business that we're putting under it with our forward contracted sales. And we're encouraged... Absolutely. Thank you much. By the most recent pricing. We're encouraged by the most recent pricing that we saw at $56 a megawatt hour for multiple years. Great. Thanks much. Thank you. Those are all the questions we have for today, so I'll turn the call back to Brent for closing remarks. Yeah, I want to thank everyone for taking the time to dial in and having interest in Hallador. And you know, we're excited, very excited about the future and what the power division is finally starting to show everyone its capabilities of, and we look forward to more exciting quarters to come. Thank you. Thank you, everyone, for joining us today. This concludes our call, and you may now disconnect your lines.