Good afternoon. Thank you for attending today's Hallador Energy first quarter 2023 Earnings Call. My name is Hannah. I will be your moderator for today's call. All lines will be muted during the presentation portion of the call with an opportunity for questions and answers at the end. If you would like to ask a question, please press star one. I would now like to pass the conference over to our host, Becky Palumbo, with Hallador. You may go ahead. Thank you, Hannah. Thank you everybody for joining us today. Yesterday afternoon, we released our first quarter 2023 financial and operating results on Form 10-Q, which 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 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 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 or uncertainties materialize, or if our understanding assumptions prove incorrect, actual results may vary materially from those we projected or expected. For example, our estimates of mining costs, future sales, legislation, and 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 some of those risks and uncertainties that may affect our future results, you should 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, a live and archived webcast of the earnings call is also available on our website. We encourage you to ask questions during the Q&A. If you are on the webcast and would like to ask a question, you will need to dial into the conference, and that toll-free number is 833-470-1428, code 018965. With that, I'll turn the call over to Larry. Good afternoon, everybody. Before I get started, I would like to define our adjusted EBITDA as operating cash flows plus current income tax expense less the effects of certain subsidiaries and equity method investment activity, plus bank interest less the effects of working capital and other long-term asset and liability period changes, plus cash paid on asset retirement obligation reclamation, plus other amortization. For the first quarter, our results were net income of $22.1 million, which equates to $0.67 basic earnings per share and $0.61 diluted earnings per share. Our adjusted EBITDA for the quarter was $34 million. We decreased our bank debt by $10 million. Our funded bank debt as of the end of March was $75.2 million, with our net funded bank debt being $72.8 million. We had letters of credit totaling $11.2 million with our banks, and our debt to adjusted EBITDA or leverage ratio was 1.2 x at the end of the quarter. I will now turn over the call to Brent Bilsland, our CEO. Thank you, Larry. Well, we're very happy with our first quarter results and the progress we continue to make towards our goals as a company. As we have noticed in past quarters, Hallador is working diligently to deleverage our balance sheet. This quarter, we made considerable progress towards that goal, reducing our bank debt by $10 million to just over $75 million. Higher average prices in our coal business resulted in $34 million in adjusted EBITDA for the quarter. As of March 31, 2023, our debt-to-EBITDA ratio dropped to 1.2 x, and our liquidity increased to $36 million. Our coal business saw production increase to 2 million tons while our cost of production decreased by $1.65 per ton. Combined with an average sale price of $55.88 per ton, for the quarter, our margins improved by $6.66 per ton as compared to the fourth quarter of 2022. Throughout the rest of the year, we expect average sales prices to remain elevated. We also continue to evaluate our cost of production as we strive to maintain our higher production or our higher margins. In connection with this, subsequent to the end of Q1, we temporarily idled our higher-cost Freelandville mine while we evaluate our production mix against market needs. In doing so, we have protected our employee base by utilizing the Freelandville employees in other roles while we undertake this evaluation. As we look to the immediate future, we continue to be encouraged by the pricing indicators for coal, energy, and capacity. As we think about the economics of Merom based on current pricing, the capacity payments that we receive should cover nearly all of the fixed costs of the plant, including maintenance CapEx, but excluding future environmental upgrades. Beginning next month, Merom fuel deliveries will be almost exclusively coal produced by Sunrise Coal, our subsidiary. I say almost exclusively as an example of the flexibility that Merom provides us. If the most profitable way to utilize our coal is to sell it to Merom and then convert it to electrons, we'll do that. Currently, we have 3 million tons earmarked for 2024 for this exact scenario. If the markets change in such a way that is more profitable to sell our Sunrise Coal to third parties and purchase fuel from Merom on the open market, then we will do so. There are numerous rules around how we price our coal to Merom, and the accounting rules make things complex. When you strip all that out and break it down to its most simple form, if hypothetically, we were to deliver our coal to the plant at our current coal production cost, then the variable cost of Merom not covered by capacity payments, including costs such as scrubber stone and other things beyond just fuel. We expect our variable costs then to be in the range of $30 per MWh. For the remaining nine months of 2023, beyond what we have already contracted to sell, we expect an additional 1 million MWh' s that have yet to be priced. For 2024, in addition to what we have contracted to sell to Hoosier, we expect to sell approximately 5 million MWhs that have yet to be priced. While we cannot share our view of market prices due to ongoing negotiations and other factors, we believe that various pricing curves for power at the Indiana Hub provide a reasonably indicative view of how meaningful Merom will become to our company starting as early as the third quarter of this year. With that ends my prepared remarks. I'll open up the call to questions. Certainly. If you would like to ask a question, please press star followed by one on your telephone keypad. If for any reason you would like to remove that question, please press star followed by two. Again, to ask a question, press star one. As a reminder, if you are using a speakerphone, please remember to pick up your handset before asking your question. We will pause here briefly as questions are registered. Our first question is from the line of Lucas Pipes with B. Riley. B. Riley, please proceed. Thank you very much, operator. Good afternoon, everyone. Good afternoon. How are you doing, Lucas? I'm doing well. I hope you're doing well as well. Thank you very much for the update. Brent, I wanted to get a little bit more color on the contributions from Merom during Q1. I wondered that... Sorry if I missed it, but I wondered what the MWh production was at Merom during Q1, and if there were, like, capacity payments included in the revenue contribution from the power side in Q1. Thank you very much for that color. We had about 1 million MWhs that we sold for the quarter, Lucas. Yes, we had close to $16 million in capacity payments in that revenue. Very helpful. Thank you. The capacity payments, how should we model that going forward? Was that kind of a lumpy one-off or would that be consistent for the remaining quarters of the year? Thank you. No, I think that. Just to reiterate, from the closing date of the plant on October 22nd of 2022 through May 31st of 2023, 100% of the electrical output of the plant is sold to Hoosier Energy, and 100% of the capacity of the plant through that time period is sold to Hoosier Energy. The economics of the plant will be fairly consistent from, you know, for the first two months of Q2, we think. Starting in June, about 30% of the capacity of the plant is contracted to them, and we have sold capacity to other parties. We'll probably see a bit of an increase in capacity payments. That's not all fully sold because part of that capacity has been offered into the MISO auction, which is ongoing. So we haven't seen the results of that yet. So far, we're pretty pleased, of the capacity or the robustness of the capacity market. Which is why we say, you know. We feel the capacity market is strong enough today and into the future currently, to, you know, cover or, you know, almost or slightly more than cover, depending on the year we're talking about, the fixed cost of the plant. When we look at energy for the balance of this year. We open up on price significantly starting in June, and we anticipate selling to the market, roughly 1 million megawatt-hours, for the balance of 2023. We anticipate selling 5 million MWh's outside of what we've already contracted for 2024. Sorry, Brent, could you repeat those last two numbers again, for the balance of 2023 and then for 2024? Correct. Basically June through December of 2023, we anticipate selling 1 million megawatt-hours, which are currently unpriced. In addition to what we have contracted with Hoosier? That is correct. Very helpful. Sorry. Thanks for the clarification. Same for 2024. We have something like 1.6 million MWh's sold to Hoosier, and then we anticipate, you know, something like 5 million MWh's to outside parties or just the MISO wholesale market, which are currently unpriced. I think the point we're trying to make here is that current market prices are significantly higher than what we have previously agreed to with Hoosier. Is that power prices or capacity prices or both? Both. Well, more so on the energy side, power prices. Got it. At today's forward curve, the unpriced portion of your power, you said it was 5 million MWh's. Did I hear that right? At what price would you expect to sell that in today's market? As I said in the prepared remarks, we have ongoing negotiations, so we don't really point to what prices are. I think it's relatively easy for the investors to look at, you know, various pricing curves out on the Indiana hub. We sell to the Merom hub, but it's usually fairly closely linked to the Indiana hub for market prices. It varies by month. Those prices change every day. Right now, the market is pretty robust. That doesn't necessarily mean we haven't, you know, hedged a lot of power. There's reasons for that. We are working to hedge some power. We'll see if we're successful or unsuccessful. Again, we're pointing to these are indicators of the market. Those are not contracted deals. The market could be stronger when we get there, it could be weaker when we get there. We're just saying that it's, you know, The markets are pretty robust right now and some people want to look at natural gas prices and say, "Well, the power prices shouldn't be high," and they are. We think there is a premium potentially being paid because the market is concerned about reliability. I mean, if you look back two years ago, nobody was talking about reliability. Last year we had a couple people talking about reliability, today I think, you know, there's all sorts of public comments from NERC, FERC, PJM, MISO. Everyone is talking about, "Oh my gosh, re-reserve margins have gotten so thin," meaning we have so little excess generation to cover load that we're seeing more and more extreme pricing events. I think this is putting upward pressure on the power market because nobody wants to be caught naked, or unhedged, you know, when we go through these events where generation struggles to meet load, which is happening more and more frequently, as baseload generation is replaced by, you know, generation that cannot be dispatched, does not have an on switch. All of that kind of leads to, because we have, you know, because our sales position with the plant starts to open up next month, and pricing is significantly higher today than what we have been selling megawatt-hours for in the rearview mirror, we think that at today's prices that Merom becomes a significant contributor to our company, you know, probably starting in July. But we certainly feel that way about 2024. It's very meaningful. We couldn't be more excited about the position our company is in with the market conditions that are being presented in front of us. We wanna make sure that excitement resonates on this call because, you know, last year we were talking about, hey, we're selling coal at really high prices, and that's gonna show up in 2023. This year, I think we're saying, "Hey, we have a very large unsold position for power," and that is gonna show up, you know, later in the year and into 2024 if prices hold, which today are thinking is they will. Very helpful. Thank you. I did something really quickly here back of the envelope, and maybe I'm way off. But if I look at the electric sales in Q1, $92.4 million, I took out the $16 million for capacity payments. Then Larry, you mentioned you sold about 1 million MWhs. I arrive at about $76 per MWh on the revenue side. Is that the right approach? No, Lucas. Remember, last quarter we talked about our gap accounting we had to do for the contract that we sold Hoosier at discounted prices. There is about $30 some million in that revenue that is just a credit because of the to reverse the discounted contract prices that we sold to Hoosier. You know, when we closed on the deal, prices had taken off, so, you know, we had sold them a discounted contract that now we have to reverse that to revenue. Okay. Okay. Accounting never makes it easy- So, so- ...on us, does it? You know, I think we have disclosed before our contract with Hoosier is $34 a MWh. Mm-hmm. You know, that significantly is less of our business starting June 1st. Hoosier gets all of our power through May 31st. You know, as Brent said, from there on, it's the power grid runs on a June 1st to May 31st fiscal year. We're selling them 1.6 million MW's out of 6.5 million-7 million we're gonna produce after June 1st. That's helpful. Thank you. Thank you for that additional color. Second topic really quickly. Last summer you disclosed that you sold 2.2 million tons at $125 per ton over several years. I wondered how much of that is for 2020 though, 2024. Thank you very much. Well. I'm not. I don't know that. Yeah, I don't know that we're prepared today to give you know, exactly what that number is off the top of our head. I mean, I think we've basically shown in the table that we expect our average price for the year to be $57. You know, and I think we're in a scenario where we feel pretty good about that because, you know, in the event that. Look, first of all, customers are doing a decent job of picking up their coal on time. That's always subject to change. What's changed for us is particularly in 2023, you know, we can currently take that coal over to the Merom Power Plant and turn it into electrons at prices that are comparable or better to those prices. you know, from that standpoint, you know, we feel really good. I don't know if that fully answers your question. I think we did show. Well, let me add-. we have. Let me add here, Brent. Also, Lucas, those were incremental tons. We actually ended up blending and extending some of those tons with lower priced contracts to blend up our price for 2023. You know, the majority of those higher priced tons are gonna be delivered in 2023. We have some carried over, but as we stated in the table, our average contacted price for, is it 2.8 million tons? Next year is about $51. Then as Brent said, we plan on taking 3 million tons to the plant, to the Merom Power Plant and converting those to MW's at a higher price than the equivalent of $57. Got it. If I assume kind of a production capacity of 7.5 million tons on the coal side, you have 2.7 million tons contracted at $51, and then you expect to sell 3 million to Merom. It leaves a little less than 2 million tons to be sold in the open market for 2024. Is that kind of the right way to think about it? We do have $1 million committed that we are now negotiating prices on. Got it. $1 million is committed on price, and then we have about, you're right, $1 million or a little less to sell. Very helpful. Where would you put the market today for Illinois Basin coal for 2024? Yeah. Again, we're in the middle of negotiations on that, so we'll decline to answer that. Understood. Fair enough. Well, I look forward to the update on the pricing front. Brent, to you and the team, continued best of luck. Really appreciate all the color. Thank you for your questions, Lucas. Thank you, Mr. Pipes. Our next question is from Kevin Tracey with Oberon. You may proceed. Great. I suppose we'll be hearing the results from the MISO capacity auction relatively soon, but it sounds like you probably sold the majority of your capacity in bilateral transactions. Can you give us a sense of where the pricing shook out for that? And maybe if you're not willing to give a precise number, can you just tell us directionally where the capacity payments for these bilateral deals came relative to where you're contracted with Hoosier? They were at higher prices than where we previously contracted. I would say this, going into the MISO auction, we felt we had 88% of our fixed costs covered heading into the auction. The auction was delayed by three weeks, so I think we expect to see the results of that, come May 19th-ish, somewhere in there, give or take a day. We'll be curious to see how those come out. Really, you know, that's a 1-year auction. What we're seeing is indications that pricing, you know, for multiple years is at, like I said before, prices that we feel will, you know, let's just say it'll cover our fixed cost of the plant, give or take $5 million, right? That kind of depends on the year. They've gone to a seasonal construct this year, so that's a new twist on the capacity markets. you know, we feel that. We feel happy from the standpoint of, you know, the capacity payments are to some degree. Well, it just kind of ensures that the market signals are saying, "Look, coal plants are needed." reliability is being talked about more and more and becoming more of a concern, which is basically just another way of saying, you know, the grid needs baseload generation that has on-site fuel. That's become an issue this year, is that, you know, some of the gas plants in some of the markets haven't been able to get fuel to the plant when they need it. Now all of a sudden, you know, there's a lot of conversation in the industry about, well, gosh, on-site fuel, which coal and nuclear plants have, you know, is an attribute that is becoming more valuable as other generating sources struggle with that, right? These are attributes that have been there all along, but when you start decreasing the fleet, you start seeing the cracks of, oh, gosh, you know, the market didn't pay for on-site fuel. It didn't pay for spinning reserve. These are attributes that always kind of showed up for free. Now you see the grid operators saying, "Well, hey, are we gonna start compensating the industry for this? Because these are attributes that we absolutely need." You know, as you have this transition, you know, there's new challenges that are created for that, created by that or revealed. All of that makes us excited about the asset that we have, excited about the economics that we're seeing the market signals show us, and seeing how meaningful that is gonna become to our company. Seeing what we feel, this isn't just a one or two year economic case. We're seeing the market kind of show us signals that look longer dated. We'll see if they're real, right? We'll see if we can contract there. early indications are, you know, we're seeing indicators that are 5 and 6 and 7 years out that show, hey, this asset's gonna be, we think, pretty profitable for quite some time. That's why, you know, you heard us in our last call saying that, our board had approved to extend the capitals to invest in ELGs because, you know, we feel this plant is gonna be needed beyond 2025 and 2028 and beyond. That could change. Market conditions change, the direction we're seeing so far is this plant is more needed, not less needed, at least by the economic indicators. For all those reasons, we're very excited. Okay. Can you put a number on what the total fixed costs of the plant you know, are in a given year? No, that's not something we've disclosed yet. I mean, again, we've only owned this asset since October 22nd, so we wanna make sure that what we project and estimate is accurate. I think we feel comfortable that, you know, capacity today looks to be, you know, very close to cover all or maybe exceed in some cases, depending on the year, of our fixed cost needs. As time goes on, we may elaborate more on that, but today we haven't disclosed that. Okay. Just to make sure I heard you right, at the beginning of the answer of the first question, you did in the bilateral capacity contracts sell the capacity for a higher price than you're selling it for to Hoosier. Did I hear that right? Yeah, you heard me correctly. Okay. Okay. In those contracts, the auction is just for a single year, am I right in thinking that often these bilateral contracts can go be negotiated for multiple years? Is that what you're doing now, or are you kind of doing it on a year-to-year basis? Well, we don't, you know, we can't. We have negotiations ongoing. It's always hard to say because sometimes negotiations start out one way and finish completely different ways. I would say this, we have enough market indicators that we feel that capacity values are robust for multiple years. The MISO auction is kind of a market where. You know, it was meant to be kind of where everybody sells an incremental amount of capacity. I think they even want to encourage everyone to either generate their own capacity or, you know, acquire that in bilateral agreements. Of course, MISO sees all of these transactions, so they very much know what's going on. You know, what comes out of the MISO auction, you know, it's kind of indicative, and it kind of isn't. You know? It's the first year that we've seen. You know, it's the first year that MISO has had a seasonal construct for capacity. It's the first time the auction has, you know, kind of dealt with this new animal. You know, I've seen a whole range of predictions of what's gonna come out of this auction, which just tells me nobody really knows, right? At the end of the day, we know this: the reserve margin in MISO, and I think will soon be followed by PJM, these numbers have gotten much thinner. You know, as We no longer have great excesses of capacity showing up in the MISO auction, which has caused prices to go materially higher. For all those reasons, we feel good about the pricing today. We will see how successful we will be about contracting capacity in the future. Okay. Just another clarification. The $30 per megawatt cost figure or MWh cost figure you mentioned in the call, that's just the variable costs or kind of the fuel and O&M costs, but doesn't include the CapEx or the other fixed costs. Is that right? We include our maintenance CapEx in that number. We do not include. Okay ... you know, any future environmental investment that we need to make. Right? We have come out and said, "Hey, we're gonna invest in technology to meet the effluent limitations guidelines standard. Yeah. We think that gets us in compliance with all of the laws that exist today. We know that there'll be additional laws in the future. We just don't know what those are or what the compliance costs may or may not be. But from a variable cost point of view, if we were to sell at-cost fuel to the plant, and this, again, this is kind of for hypothetical 'cause there are market rules around, you know, how we have to price coal to ourselves, right? That can get a little confusing for anyone trying to follow that. What we're saying is, hey, hypothetically, if we took our coal at cost, took it to the plant, where would our variable cost plus scrubber stone, plus maintenance, CapEx, all that kind of stuff wash out? That number is roughly $30 per MWh. Okay, that $30 is kind of everything but the environmental CapEx you're gonna have to do for the next couple years? Correct. Fuel and so on, so. Fuel, O&M, and maintenance CapEx. Yeah. Got it. Okay. Yeah. I must say... Okay. Last question. maintenance CapEx would be in our fixed cost. Our variable cost, we look at that, and that is fuel, that is scrubber stone, that is, you know, NOX compliance, things like that. Okay. Okay, last question. Your comment that you expect to sell 1 million MWhs to non-Hoosier parties this year, that would seem to imply the plant's inventory constrained in the second half of the year. I guess I'm wondering if there's potential upside to that 1 million MWhs if you're successful in sourcing more coal elsewhere? I think we've looked at this. You can always source more coal elsewhere, it's just a matter of price. I think what we're looking at is when we look at the power curve for 2023, we look at the obligations that we have to other parties, you know, we estimate, based on those prices today, that we will sell an additional 1 million MWhs that are unpriced. Okay. Great. Thank you very much. All right. Thank you. Thank you, Mr. Tracey. Once again, it is star one to ask a question. The next question comes from Kenneth Pounds with Castleberry Advisory. You may proceed. Hello. Good morning. Great job, gentlemen. two questions, and maybe you kind of covered it a little bit already. 2024, you said, 6.5 million-7 million MWhs is what you think you can produce next year? Yeah, you're a little choppy on the voice connection. I think you said... I think what I heard you say is we plan to produce somewhere around 6.5 million MWhs in 2024. That is correct. what is the nameplate capacity for the plant? Nameplate capacity for the plant is 1,070 MW's. Okay. Well, okay, that translates into, you know, how does that translate to the number you just gave us, 6.5? Well, 1,070 a day, I mean, it translates to about 8.15. Perfect. Thank you. Sorry. 8.1. Okay. How much coal extra would you have to produce for this to try to reach that number? I'm sorry, sir, the connection is bad, and we're just not hearing you. Okay, thank you. Thank you. Thank you, Mr. Pounds. The next question is from the line of Mike Rybak with Butler Hall. You may proceed. Hey, how you doing? Thanks for taking my questions. Hey, Mike. Just to follow up on the last question, right? It's an impressive number if you guys can do kind of 6.5 million MWhs. What drives... I mean, just looking at historically, right, the plant's never really done more than, I don't know, 5.5, something like that. Obviously I respect that you guys are coming in and, you know, are looking to run it better. Is there something structurally that's changing that gives you guys confidence that, you know, you can increase output by 1 million MWhs? Yeah. Power prices are considerably higher than in the past. Okay ... you know, when you looked at the ratio of fuel cost, and, you know, we're vertically integrated, Hoosier was not. So when you look at the ratio of fuel cost to power prices, we're in a better market today than they were historically. Even if you look at last year, they had pretty strong power prices last year, but they had already kind of, you know, began, you know, backing down their maintenance CapEx and those sorts of things because they were gonna close the plant, right? That was the game plan. Then we, you know, we were able to acquire the plant. So we've began a process of reinvesting in maintenance of the plant to get it... It, and it wasn't in a bad condition, but to get it in a better condition, so that we can achieve these higher numbers. We think that that is doable. The market signals today are calling for that to happen. Again, we haven't contracted a lot of this stuff, right? All we're really trying to say is, Hey, here's what we think today based on the market signals today. Market signals change quickly for the better, for the worse. I think the general trend that has been revealed, and we've talked about this in the past, you know, if you look at MISO prior to, and I'm going from memory here, so don't quote me exactly, but you'll get the idea. Prior to 2016, I don't think they had had any Maximum Generation Events, meaning where the grid operator comes out and says, everybody turn on because we're struggling to meet load. In the trailing 12 months, it's been something like 11 x they've made that phone call. What we're saying is because there's been such a rapid closing or retirement of baseload generation, and a large percentage of that baseload generation has been replaced with generation that cannot be turned off. There isn't an on switch located anywhere on a solar panel or a windmill, right? These assets kind of come on when the wind blows and the sun shines. Solar goes home every night. There's not hardly any battery capacity in the MISO system today. Because of that, the smaller fleet that remains has to work harder, right? That is what we're seeing in the pricing of the market. That's what we're trying to communicate. We think the opportunity is bigger than it was in the past. Right. No, that makes sense. What just, you know, what power price, I guess, where would power pricing have to go? How far down would they have to go for you guys to say, you know, 6.5 is not the right number? I mean, it seems like, you know, relative to the curve today, you could still see power pricing, you know, I don't know, they go down to $40 per MWh. It still seems like that would be achievable. I mean, we're vertically integrated. There comes a point where we would make 0 profit at the plant or make $0.50 of profit at the plant and $0.50 of profit at the coal mine, right? Arguably, theoretically, in that scenario, we would still run. You know, where exactly that number is, that's not something we're going to get into today in that analysis. I think our point is that we're at the opposite end of that scale. The markets are pretty robust. They do change quickly. We saw, you know, a lot of change in energy markets last year. Last year was probably the most dramatic up and down of the, I don't care what energy market it was, whether it was oil, whether it was coal, whether it was natural gas, whether it was LNG, power markets. I mean, it's been very volatile. The opportunity is there. We're excited about what we're seeing. We're cautious to say these are the exact numbers when we don't have all of that contracted. You know, it's kind of this double-edged sword for us of trying to indicate how good we think it can be without overstating our position. What we're saying today is capacity signals look good. Coal pricing signals look good. Power pricing looks excellent as well. That's the condition we're in. We think because our power plant is going from being 100% sold out this month to, or significantly sold out this month to we open up into a pretty large unsold position starting next month. You know, we'll see what the power prices bring. If the entire year is 65 degrees in the Midwest, power prices will be terrible, right? I mean, it's just that there won't be that much load to meet. If we see 110 degree heat indexes, look out. It's going to be crazy, right? The grid is really starting to struggle. You've had the grid operator of MISO say publicly that MISO is being backed up by PJM and PJM is backing up MISO. If it's hot or cold in either of those two markets at the same time, there's not going to be any spare electrons from one market to share to the other, right? This is where we see these extreme events where power prices go to, you know, a couple thousand dollars an hour, a MWh. That's, you know, the market is saying, well, hey, if more of those type events are out in the future because there's a lack of generation, we're going to pay a premium above the price of, you know, a gas generator or a coal generator because we don't want to be caught, right? When the tide goes out, you find out who's naked, as they'll say. The market is saying we don't want to be caught in that scenario. You know, what we think we see is the market saying we'll pay a premium to stay out of that event. Again, if power demand stays low, that premium will dissipate and go away. If we see, you know, extreme temperatures, that power premium will increase. Okay. This transition is, you know, everyone wants to look at the past and say, "Well, this is what it should be because this is what it was three years ago." We're in completely different energy markets than we were in three years ago, right? Right. We have forced a lot of variable generation into the grid, and that creates new challenges. The power markets are now forced to pay to try to, you know, solve those challenges. Just two questions. One on Merom and one on the core. In Q1, I want to understand this. If we just look at, you know, your electrical revenue was $93 million or so. You had that $33 million that was a kind of a contract liability amortization. Net of that, it was about $59 million. Sixteen million was about the energy capacity revenue. Mm-hmm. The remaining kind of generation revenue is about $43 million. I think you noted that, you know, you generate about 1,000 MWhs. And if you're getting paid $34 per MWh, shouldn't it be $34 million? I was having trouble reconciling why the generation revenue was $43 million. There's capacity damage in that number as well. He took those out. I think, I mean, I know it's not $9 a megawatt, but we do get some true ups and true downs and excess payments, Mike, based on if we over-generate for the day and prices went up. I can look at that and send you an email of where we're at exactly. Okay. Um- Okay. 'Cause your theory is correct. I mean, it's $34, but we don't net exactly $34, when we have some excess power that, for instance, if we bid in 900 MW's for the day and we produce 910 for the day, we do get that excess power that doesn't go to Hoosier. That will be most of the difference. Okay. Then to the question. And- The first question. On the carryover tonnage, the, you know, you guys signed like 2.2 million tons and at $125. I think like the majority of it is in 2023. Obviously you guys haven't specified how much in 2024. I was playing around, you know, if I just say, okay, let's just say 0.4 million tons is in 2024, right? Mm-hmm. At $125. You guys noted that for next year, right, for 2024, you have about 2.7 million tons at $51, which includes these, you know, tonnage at $125. In my kind of, you know, quick back of the envelope, if it's 0.4 million tons, that implies the rest of the tonnage, the, you know, the 2.3 million tons in this example, is like contracted out at a $38 price. I'm just trying to figure out why it's so low. Well, I mean, I guess we can't really speak to what all our other contracts are or aren't. I would say this. I mean, we went from a period of time... You know, we have multi-year contracts, right? You know, we have prices that were low and we have prices that were high. Some of those lower prices came from coal that we priced two, three years ago, right? You know, I don't want the market to get hung up on, well, exactly how many of these 100... Like, we're showing you in our table what our average prices are. You know, I think if you're trying to create your model and look at what cash flow is in the future or whatnot, look at the average price. Look, here's how many tons we have. Here's what our cost production has been. Here's the volumes that we think we're gonna move. I think you'll get there. I think you'll get to where you're trying to be. Okay. Thank you so much. Best of luck. Appreciate the questions. Thank you. Thank you, Mr. Rybak. Once again, to ask a question, press star one. There are no additional questions waiting at this time. I will turn the call back over to Brent Bilsland for any further remarks. Yeah. Once again, I think we are very excited about the quarter. We're very excited about, you know, the future that Merom brings to our company, the pricing signals that we're seeing from the market, and we appreciate all the interest from the participants of the call today. With that, I'll end the call and get to work for next quarter. Thank you. Bye-bye. That concludes today's Hallador Energy first quarter 2023 earnings call. Thank you for your participation. You may now disconnect your lines.