Good afternoon, ladies and gentlemen. Thank you for joining today's Hallador Energy Second Quarter 2023 Earnings Call. My name is Tia, and 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 on your telephone keypad. I would now like to pass the conference over to your host, Rebecca Palumbo, Director, Investor Relations. Please proceed. Thank you, Tia. Thank you everybody for taking the time to join us today. Yesterday afternoon, we released our second quarter 2023 financial and operating results on Form 10-Q. It 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 the call up to your questions. Before we begin, please note that the discussion today may contain forward 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 of 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 other 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 can 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 this earnings call is available on our website. We encourage you to ask questions during the Q&A session. If you are on the webcast and would like to ask a question, you will need to dial into the conference number, and that toll-free number is 1-833-470-1428, access code 813157. With that, I'll turn the call over to Larry. Thanks, Becky. Good afternoon, everyone. I'm gonna go over the review of our operating results. Before I do, I want to make the definition here of adjusted EBITDA, which is operating cash flows, plus our interest expense, plus depreciation, plus asset retirement obligation reclamation, other amortization, then less any effects of our subsidiary and equity method investments, less any effects of working capital changes. Our net income for the second quarter was $16.9 million, which resulted in $0.51 per basic earnings per share or $0.47 diluted earnings per share. For the six months ended in June, we had $39 million of net income, which resulted in $1.18 basic earnings per share and $1.08 diluted earnings per share. Our adjusted EBITDA for the quarter was $35.3 million, and for the six months, $69.3 million. Our bank debt decreased by $1 million for the second quarter and $11 million for the six months. Our funded bank debt as of June 30th was $74.2 million. Our letters of credit were $11.2 million, and our net funded bank debt, which was our funded bank debt less cash, was $71.9 million. Our leverage ratio, which is defined with our bank as debt to adjusted EBITDA, was 0.94x. I want to turn that call over now to our CEO, Brent Bilsland, to go over the highlights of the quarter. Thank you, Larry. Thank you, everyone, for joining today. Much like our first quarter, we remain pleased with the progress we continue to make during the second quarter towards our company goals of increasing profitability, increasing company liquidity, and reducing balance sheet leverage. The realization of higher priced coal shipments led to cents, including to Merom. without that, $20.96, despite higher production costs. Coal production was strong, we were able to meaningfully increase our coal inventories throughout the quarter. We intend to leverage this increased inventory to further supplement our power production and position ourselves to take advantage of the increased power needs anticipated in the summer months and throughout the second half of the year. Additionally, on August second, after the close of the quarter, we finalized a new credit facility led by PNC Bank. The highlight of this new facility is the improvement of our liquidity position to $56.9 million as of June 30th. The strong sales from this quarter resulted in net income of $16.9 million in Q2, and the best net income we've had over the first half of the year at $39 million. This growth enabled us to make great strides towards our goal of deleveraging our balance sheet. As we continue to execute on our overall plans, we believe that Hallador has dramatically improved both the quality of our business, with the addition of Hallador Power last October, and the quality of our balance sheet by reducing our debt to EBITDA multiple to 0.94 x at the end of the second quarter. Our coal business continued to thrive with an average sales price of shipped coal during the quarter at $65.44 per ton, including shipments to Merom, $63.27 per ton. I'm sorry, excluding sales to Merom. While some of those higher price shipments will tail off through the remainder of the year, we expect that the average price will remain above $55 per ton. At the same time, coal costs were over $41 per ton, which we attribute mostly to inflationary pressures. Notwithstanding the increased costs, our second quarter margins, before eliminations of Merom sales of $23.92, were an improvement of $6.85 over the first quarter of 2023. Comparing operating revenues from coal operations to the second quarter of 2022 highlights the impact of these high-priced contracts. We saw operating revenues from coal operations increase 73% over the same quarter in 2022, due largely to the increase in the average sales price for coal. Operating revenues in Q2, 2023 include $23.6 million sold to Merom that was eliminated in consolidation. Our healthy coal production during the second quarter allowed us to grow coal inventories by $9.3 million. This growth provided us with the flexibility to ship. Excuse me. It provides us with the flexibility to ship additional coal to Merom if the market so dictates, and ultimately will allow us the option of generating more megawatt hours in the second half of the year than previously planned. This flexibility is especially important as Hallador Power completed its obligation of selling 100% of the output to Merom's original owner. Even with some of the initial limitations on where and to whom we could sell our output, Hallador Power contributed $9.2 million in net income during the second quarter. Starting in June 2023, as some of these contractual limitations expired, approximately 80% of our potential output from the plant became available to sell to the open market. As our operations at Hallador Power continue to develop, we are excited for the meaningful contributions that we expect Hallador Power to make in the second half of the year and beyond. On August second, we successfully closed the new $140 million credit facility led by PNC Bank. The facility consists of a $65 million term loan with a maturity of March 2026, and a $75 million revolver with a maturity of July 2026. As stated before, as of June 30th, our liquidity improved to $56.9 million. This new facility is important for multiple reasons, including providing us with additional flexibility to make forward power sales and to react quickly to market opportunities. We are encouraged by the general outlook on future power pricing, and our increased liquidity places us in a better position to potentially lock in future profits. As I said at the start of my comments, I'm incredibly pleased with the quarter results and the progress that Hallador continues to make as a company. With that, I'll open up the line for any questions that anyone may have. Absolutely. We will now begin the Q&A session. If you would like to ask a question, please press star followed by one on your touch-tone 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 to allow questions to generate in queue. The first question comes from the line of Lucas Pipes with B. Riley. Please proceed. Thank you very much, operator. Good afternoon, everyone. Good afternoon, Lucas. My, my, my first question is on, on coal pricing. You have about 3.6 million tons unpriced for 2024. I wonder what the mechanism might be for pricing those tons and where you see the market today. Thank you very much. Well, a large percentage of that business is tons that are committed to ourselves at the Merom Power Plant that we have yet to price. So we will look at the market indicators and basically set those prices so that it's a fair transaction for both, Sunrise and the Merom Power Plant. There's, there's rules around that, that a market monitor will review. I mean, that's kind of how, how we do that. If you look at, you know, the general pricing curve, you know, it'll be something, something in that range. Got it. And can you remind me how many tons are likely to go to Merom in 2024 out of your own production? We figure about 3 million tons. Essentially the committed but unpriced portion of your book, should I think of that going to Merom? Yeah. $3 million of the $3.6 million is what's committed and well, $3 million of the $3.6 million is what's going to Merom. Got it. You really just have, like, 600,000 tons that are uncommitted, unpriced, that you have to find a home for? Yes. That's, that's helpful. Thank you. Two, two quick questions on the contract liability. The, you know, as part of the consideration, I, I think you marked it to $184.5 million as, as, as a PPA. Based on where power prices are today, could, could you, could you give us a sense what- where, where that liability would stand? Re- somewhat related, the amortization of the contract liability of, $19.6 million during the quarter, would that be, within, captured within your operating expenses on the income statement? Or, or, or, where would, how would that flow, flow through? Thank you very much. Lucas, the contract liability runs through revenue, so it decreases revenue. If you'd look at, Note 15, part of the corporate and other eliminations of $23 million for the quarter, the lion's share of that note decreases revenue. Increases. Increases revenue. Then the $23 million. is the intercompany sale to, from. So Sunrise sold coal to the power plant, and the power plant did not burn that yet, so that's part of that elimination. Okay. Okay. Maybe we can follow up on that offline, but, but, yeah, that's. Okay. Yeah, I, I, I, yeah, what, what got me on this question is the, just that when I, when I looked through the reconciliation of, of revenue, I think that's page 22 on the 10-Q, where, where, it shows the capacity revenue, the delivered energy PPA revenue, and that adds up to the $71 million that you also show in the income statement. Then there's the amortization of the contract liability of $19.6 million, to, to kind of back into, I guess, what would be a, True sales. Yeah. Exactly. Exactly. Yeah. I'm just trying to figure out. Yeah, so the $19 million, the $19 million is in revenue for the purchase contract liability that we got. Right here, we're just backing out that $19.5 million out of revenue to show you what a normalized revenue will be after that is amortized. Yes. essentially the $71 million. The top number, the $71 million is GAAP accounting, which you know. Yeah Includes the purchase price, and then the $51 million would be normalized revenue if we had no purchase price adjustment. Got it. the $51 million. And the? $51 million, the $51 million is sold power, capacity and power. Yeah. Yeah, but, but just, just to be clear here, the and again, maybe we can follow up on this offline, but, but your, essentially, the $71 million is a, is, is a more market-based figure. Is that, is that right? More market-based back in October. Yeah, I mean. Okay One of the issues, one of, one of the issues here is when you negotiate a transaction such as this, it takes a lot of time, right? The price, you know, the seller would say, "Well, hey, look, I've got the coal purchased to generate. Mm-hmm My electrons through May of 2023," right? Because that was when they intended to close the plant. Yeah. They're saying: Well, look, I'll, I'll enter in an agreement with you where we sell you coal at a certain price and buy electrons at a certain price. Then when we get to the closing of the transaction, which was probably quite some time later, we have to. February to October. February to October, we have to mark that to market, right? There was a lot of. Yeah A lot of volatility in the market last year. That's essentially what happened, and now, now we're accounting for that, for that mark to market. In February, we were close to market. By the time we closed in October, the market had taken off, as everybody knows, so we had to mark those contracts to market at the time. Lucas, you're right in saying that the $71 million is market, but it was market in October, not necessarily market today. Got it. Okay. This is all helpful. Thank you. so, I, I guess what I'm trying to get at is market today, where would you put it both on the dollars per megawatt hour and then the capacity revenue? Well, that's, that's not something that we disclose because we always have ongoing trading, as far as selling the capacity and selling of energy. There are certainly market curves out there that you can look at for, you know, Indiana Hub. We actually sell to the, to the, to the Merom Hub, but there's a more public market of the Indiana Hub, I think, that can give you a feel for what electrons are selling for at, at various periods of time. Capacity is a little tougher. The capacity market auction is the most, you know, visible mark to market, but we have found that those pricings have, have been all over the place. To us, the MISO capacity auction prices have really not been very correlated to the actual price that capacity is trading at. I think we've said in past quarters that we feel that we are able to sell capacity at prices that, you know, relatively cover our fixed costs. Okay. Got it. Yeah. Most of our capacity has been sold through bilateral agreements with various utilities and trading companies, and very little volume, for us, is actually sold through the MISO auction. And Lucas, I'd like to also point out here, you asked about the $19.5 million. We also, in that same, you know, in the same transaction with Hoosier, we also we got, you know, we sold power under market from the, in October. We also got a coal contract way under market in October as well. That is what the $12.9 million is on page 22 for the amortization of the contract asset. You know, so they kind of they offset a little bit. You know, we, we sold power. Yeah Less than market in October because of because we started in February. We also got a coal contract less than market, that we had to pay less than market for. Got it. Okay. That, that's kind of what, that's kind of what the table on page 22 is trying to, you know, add even more clarity to, is: Here's how many megawatt hours we sold, here was our capacity revenue, here was the price we got per megawatt hour, and here was our cost per megawatt hour. We've mentioned here on the call what our net income was for the plant. We're trying to add more clarity there. We realized the GAAP accounting around the. Purchase Purchase, asset, and liabilities, can make it a little challenging to follow. Yeah. Now, this is, this is helpful. Okay. I really appreciate the color. Best of luck to the entire Hallador team, and, and, and I will turn it over. Thank you. All right. Thank you, Lucas. Thanks, Lucas. Thank you, Mr. Pipes. Again, to ask a question, please press star one. We will pause here briefly to allow questions to generate in queue. The next question comes from the line of Kevin Tracey with Oberon Asset Management. Please proceed. Great. Thank you. Brent, I appreciate this page 22, all the disclosures you've added here. I'm gonna ask you for another one. I think what most investors are keen to know is kind of what the non-fuel cost of the power business is. There's obviously a lot going through kind of the fuel expense line with this amortization of the coal contract asset and these intercompany sales from Hallador and so on. Do you have the kind of fuel expense in the quarter handy, or would you be willing to disclose that? That's, that's not something that we've prepared to disclose today, but we'll certainly take that into consideration for future quarters. Okay. Yeah, that'd be great. Maybe I could ask it a different way, or this variable expense, that you've disclosed, and I think it came in at roughly $11, or sorry, sorry, $30 per megawatt hour. Do you have a sense of what kind of the non-fuel variable cost per megawatt hour should be on an ongoing basis? Well, I, well, we've disclosed in the past that our capacity covers that cost, our capacity revenue. I think that's all we're willing to do this quarter. Okay, just to be clear, the capacity revenue covers the fixed cost, right? Not the variable cost. Or are you talking about capacity revenue covering kind of all of your non-fuel? Yeah. No, you're correct, fixed cost. Fixed cost. We've stated that for the last. Okay Three quarters, that our capacity revenue covers fixed cost. Yeah. are you. If you're asking. Okay. Are you asking about non-fuel variable cost? Is that what you're asking about? Yes, yes. Yes, that's what I'm asking. Yes. I mean, it is in the variable cost, and I mean, the lion's share of our variable cost is fuel. Okay, fair enough. Can you talk about what the inventory position looks like at Merom? I mean, you talked about hopefully being able to generate more electrons in the second half of the year than maybe you envisioned at the beginning of the year. Where does inventory stand at Merom? I think you have 4 million tons of kind of contracted price tons to sell to third parties in the second half. Is there a chance that your customers might be willing to defer some deliveries outside of this year, and that might unlock more inventory to burn at Merom? Well, I mean, as far as what our customers are willing to do, that, that kind of changes on a daily basis. Yeah, I mean, I think what we said in the call is, what we've said in prior calls is, you know, the power, the, the, the power or coal prices last year took off. We sold a large percentage of our coal to third parties. Now, you know, because our production has been, well, has exceeded sales, we are generating inventory in the first half of the year that we think that we'll be able to burn profitably in the second half of the year. That's gonna be dictated by the price of power, right? I mean, we, we, these are not contracted forward power sales for the most part. The, the benefit and the burden of having our power book, you know, 20% contracted, 80% open market for the balance of the year, is we think we can achieve higher prices than what we're previously contracted for in the first half of the year, but that will be up to the market, right? I mean, some of that is weather dependent, some of that is gas price dependent. Power prices change every day. All we're saying really is, we have more fuel, and because of that, we'll, we'll, we'll be looking to burn and generate more megawatt hours in, in the back half of the year. Which maybe another way of saying is there's potential, depending on power prices, for the power plant to make more money in the second half of the year than in the first half of the year, but that is wholly dependent upon what we see in the market as far as the price of power. We just have the inventory to do it, should the market show us values that make sense. Would you say the power plant is not inventory constrained? To the, to the extent the power prices are favorable in the second half of the year, could you run the plant at a high capacity factor? Is there a point where you might run out of inventory? No, we feel we could run at a high capacity factor if the market showed us the appropriate pricing. Okay, great. On the cash flow, the free cash flow conversion hasn't been great in the first half of the year. Now that you've completed your coal purchase contract acquired with Merom, is it fair to say that you're gonna burn down a lot of that coal inventory in the second half, and free cash flow should be quite robust in the second half? I didn't hear you say, I think the prior goal was to hopefully be net debt zero sometime early next year. Is that something that you reiterate? Second quarter, yes, we think we'll be net debt free. To answer your question on the inventory, yes, we plan on drawing inventory down as much as possible at the end of the year. I think we had, like, $9.4 million increase in inventory, which, as you point out, decreased our cash flow. We expect that to turn around and then some, because we will draw our inventories down. You know, it's dependent upon power prices, dependent on customer show up, but our plan is to draw inventory down to a very low inventory balance at the end of the year. Depending on power prices. I said that. Yeah. Okay, okay. Lastly. It's totally dependent on the, on power prices. We have the coal sold to third parties, so, you know, they're obligated to come and get it, whether they. I mean, there'll be something there if they don't come and get it. I mean, it'll be a carryover, it'll be some kind of settlement. Then power prices. Okay. Lastly, on the, on the coal cost per ton is kind of low forties, and a good expectation going forward? We, we think we, we think we can get those lower. You know, two years ago, we were at 32%. We're I don't know if we'll ever get back there with inflation, but we are working on things at the mine to help geology, to help mining conditions, and more efficiency. We think we can get them down from 41%, but I'm not gonna throw a number out there. We are working on. Okay lowering them and think we can. Okay. Thanks very much, guys. Thank you. Thank you. Thank you, Mr. Tracey. Again, to ask a question, please press star one. We have a follow-up question from line of Lucas Pipes with B. Riley. Please proceed. Thank you very much, operator. Thank you. My follow-up question. Just looking at the megawatt hours sold in the first quarter and the second quarter, 2023, we, we had that drop from 1,262 now into 1,043. Is that just seasonal? Kind of looking ahead, at what level do you look to run the plant going forward? Thank you very much. Well, again, that's, that's somewhat power price dependent, Lucas. You know, in the first quarter, 100% of the output was committed to the seller of the plant, and, you know, that, that essentially was the pace that they wanted us to run at. In the second quarter, two of the three months were in, in the same. You know, managed the same way. Really, June was the first time that, you know, we were in position to, you know, sell the majority of our electrons to market, and that kind of dictated the pace of the plant. You're also in the shoulder month right there, right? I mean, you've got. April. You had two shoulder months in the second quarter. Only one. I mean, you know, like, March really isn't- Correct. Not really a shoulder month. April wasn't very hot. You know, you typically expect your plant to run more in July, August, September. Those are hotter months than April, May, June. We'll see what, what, what winter brings. You know, does winter show up in November, or does winter show up in December, or does it show up in January? You know, the, the, the power business is a much more seasonal business, particularly when, you know, we have more market exposure versus, you know, what we've typically experienced in, in just the coal business, right? Typically, the coal business, you've got it under contract, and it really just kind of comes down to, well, hey, I have visibility on the sales. What are my cost of production, and what volume am I gonna be at? Said another way, I think that longer term, you'll, you'll, you'll see the plant probably run more at, you know, 1.5 million megawatt hours per quarter. Those will be probably a little more aggressive in the heating and cooling season and a little lighter in the shoulder seasons. From a volume perspective, that's where we'd like to be. In, in June, was the utilization rate higher or lower than in April, I think? Prices were pretty soft in June. It was pretty mild here in the Midwest. Quite frankly, you know, heat showed up basically in the first three weeks of July. July was pretty good. I think it's been relatively mild here. Early August For the first week of August, but, you know, we'll still see what, what the summer brings. gas prices affect this, this too. You know, that said, I think long term, I think the, I think the margin potential of the power business is very good. So I think, you know, we haven't really had. You know, you'll look to see us price a little bit more of our power going forward, and hopefully next quarter we can be in a position to disclose some more of that. I, I think the market will be pleased with the pricing that we're seeing. We'll talk about those deals when they, when they're, when they're signed, and we can report it. That, that's, that's helpful. Thank you. back, back to page 22. Right, you net out the amortization. You show that average price per megawatt hour of delivered energy and PPA revenue of $32.89 per megawatt hour, and you show that cost on a variable basis of $30.05. Are those two metrics may be the best to kind of where the market is today, to model this business going forward? I, I don't think on the sales side, that is not market today. I think on the cost side, yeah, you're starting to see a couple quarters here of where our costs, you know, are, are at for the plant. Yeah. That's both fuel and variable costs. Cause, cause realize, like, second quarter, second quarter, Lucas, as Brent said, it is a shoulder month, so it's lower prices to begin with, and it was quite cool in April, May, and June wasn't that great either, so. So, so kind of. When I say, when I say cool, not cold. Yeah. Yeah, yeah. Excuse me? No, that's, yeah, that's, that's clear. In, in other words, the, the, kind of, at, at, at current market prices, the average price for a megawatt hour delivered energy and PP A and the PPA revenue would, would be somewhat higher? Significantly, yeah. I mean, I, again, you know, look, as it kind of gets into what time period are we talking about, right? I mean, if we're talking about spot power tomorrow, you know, if the temperature is mild and gas prices are cheap, that's not gonna be a very good price. If we're looking further out on the curve, I think we're pretty, pretty excited about what we see out there. It's, it's. You know, I just, I just don't want to. First of all, we have ongoing negotiations, so I don't, I don't want to tip our hand. Also, you know, I don't want to confuse the market either, because pricing today is, is potentially very different than pricing two years from now. Got it. so, no, no, that's, that's, that's very helpful. Again, thank you for taking my follow-up question, and, and again, best of luck. I appreciate you. Thank you. Thank you, Mr. Pipes. Again, to ask a question, please press star one. We will pause here briefly to allow questions to generate in queue. There are no additional questions left at this time. I will pass it back to Brent for any closing remarks. I want to thank everybody for their interest in Hallador and joining our call today. We look forward to reporting more great results to you all in the future. Thank you. That concludes today's conference call. Thank you. You may now disconnect your line.