Good afternoon. Thank you for attending today's Hallador Energy's First Quarter 2023 Earnings Call. My name is Hannah, and I will be your moderator for today's call. I would now like to pass the conference over to our host, Becky Palumbo with Hallador. You may go ahead.

Thank you, Hannah, and 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 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. And 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 effect 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 equated 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 1.2x 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 1.2x, 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 and 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 provided. It's the most profitable way to utilize our coal is to sell it to Merom and then convert it to electron; we'll do that. Currently, we have 3 million tons earmarked for 2024 for this exact scenario. However, the markets changed in such a way that is more profitable to sell our Sunrise Coal to third parties and purchase coal for 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. But when you strip all that out and break it down to its most simple form, if hypothetically, we would deliver our coal to the plant at our current coal production costs, 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 megawatt hour. For the remaining 9 months of 2023, beyond what we have already contracted to sell, we expect an additional 1 million megawatt hours that have yet to be priced. For 2024, in addition to what we have contracted to sell to Haute Energy, we expect to sell approximately 5 million megawatt hours that have yet to be priced. So 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. So with that, that ends my prepared remarks. I'll open up the call to questions.

Our first question is from Lucas Pipes with B. Riley.

Thank you very much for the update. And Brent, I wanted to get a little bit more color on the contributions from Merom during Q1. And I wondered — sorry if I missed it, but I wonder what the megawatt hour production was at Merom during Q1? And if there were like capacity payments included in the revenue contribution from the power side in Q1?

We had about 1 million megawatt hours that we sold for the quarter, Lucas. And yes, we had close to $16 million in capacity payments in that revenue.

Very helpful. And the capacity payment is that, 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?

No, I think that — so just to reiterate, from the closing date of the plant on October 22, 2022, through May 31, 2023, 100% of the electrical output of the plant is sold to Haute Energy, and 100% of the capacity of the plant through that time period is sold to Haute Energy. And so the economics of the plant will be fairly consistent for the first 2 months of Q2 we think then starting in June, about 30% of the capacity of the plant is contracted to them, and we have sold capacity to other parties. So 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. But so far, we're pretty pleased with the capacity or the robustness of the capacity market. And which is why we say we feel that the capacity market is strong enough today and into the future currently to cover almost or slightly more than cover depending on the year we're talking about the fixed costs of the plant. So then 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 by roughly 1 million megawatt hours for the balance of 2023, and we anticipate selling 5 million megawatt hours outside of what we've already contracted for 2024.

Sorry, Brent, could you repeat those last 2 numbers again for the balance of 2023 and then for 2024?

Sure. So basically June through December of 23, we anticipate selling a million megawatt hours, which are currently unpriced.

In addition to what we have contracted with Hoosier.

That is correct. Very helpful. Thanks for the clarification. And then same for 2024 we have something like 1.6 million megawatt hours sold to Haute, and then we anticipate something like 5 million megawatt hours 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 Fusion.

And is that power prices or capacity prices or both?

Well, more so on the energy side, power prices.

Got it. So at today's forward curve, unpriced portion of your power, you said it was 5 million megawatt hours. Did I get that right? And at what price would you expect to sell that in today's market?

Yes. So as I said in the prepared remarks, we have ongoing negotiations, so we don't really point to what prices are. But I think it's relatively easy for the investors to look at various pricing curves out on the Indiana Hub. We sell to the Merom Hub, but it's easily fairly closely linked to the Indiana Hub for market prices. It varies by month, those prices change every day, but right now, the market is pretty robust. That doesn't necessarily mean we haven't hedged a lot of power. There are reasons for that. We are working to have some power. We'll see if we're successful or unsuccessful. So 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 there are 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. And we think there is a premium potentially being paid because the market is concerned about reliability. I mean if you look back 2 years ago, nobody was talking about reliability. Last year, we had a couple of people talking about reliability. And today, I think there's all sorts of public comments from NERC, FERC, PJM, MISO, everyone is talking about, "Oh my gosh, 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 making it or unhedged 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 generation that cannot be dispatched and does not have an on switch. So all of that kind of leads to because we have 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 probably starting in July. So but we certainly feel that way about 2024. So it's very meaningful. We're 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. So we want to make sure that excitement resonates on this call because last year, we were talking about, hey, we're selling coal at really high prices, and that's going to show up in 2023. This year, I think we're saying, hey, we have a very large unsold position for power, and that is going to show up later in the year and into '24 if prices hold, which today, we're thinking as they will.

Very helpful. 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. And then, Larry, you mentioned you sold about 1 million megawatt hours. So I realize about $76 per megawatt hour on the revenue side. Is that the right approach?

No, Lucas, remember our last quarter, we talked about our GAAP accounting we had to do for the contract that we sold Haute at discounted prices. So there is about $30-some million in that revenue that is just credit because of the — to reverse the discounted contract prices that we sold to Haute when we closed on the deal; prices had taken off. So we had sold them a discounted contract that now we have to reverse that to revenue.

Accounting never makes it easy, does it?

Yes, I think we have disclosed before our contract with Haute is $34 a megawatt hour. But that significantly is less of our business starting June 1. Haute gets all of our power through May 31. And then as Brent said, from there on, it's — the power grid runs on a June 1 to May 31 fiscal year. So we're selling them 1.6 million megawatts out of $7 million that we can, $6.5 million to $7 million, we're going to produce after June 1.

That's helpful. Second topic really quickly. Last summer, you disclosed that you sold 2.2 million tons at $125 per ton over several years. And I wondered how much of that is for 2024.

Not exactly.

I don't know — yes, I don't know that we're prepared today to give you exactly what that number is off the top of our head. But I mean, I think we've basically shown in the table that we expect our average price for the year to be $57, and I think we're in a scenario where we feel pretty good about that because in the event that first of all, customers are doing a decent job of picking up their coal on time, that's always subject to change. But what's changed for us is particularly in 2023, we can currently take that coal over to the Merom Power plant and turn into electrons at prices that are comparable or better to those prices. So from that standpoint, we feel really good. So I don't know if that fully answers your question. I think we did show in the table that we had…

Well, let me add here, Brent. Also, Lucas, those were incremental tons. We actually ended up blending and extending some of those tons with lower price contracts to blend up our price for '23. So — and the majority of those higher priced tons are in '20 going to be delivered in '23. We had some carried over, but as we stated in the table, our average contracted price for is 2.8 million tons next year is about $51. And then as Brent said, we plan on taking 3 million tons to the plant, the Haute to the Manpower plant and converting those to megawatts at a higher price than the equivalent of $57.

Got it. So 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 million, and then you expect to sell 3 million to Merom. So 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?

Yes, we do have $1 million committed that we are now negotiating prices on so — $1 million is committed on price, and then we have about a little — $1 million or a little less to sell.

Very helpful. Would you put the market today for Illinois Basin coal for 2024?

Yes. So 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. And Brent, you and the team continue to best of luck.

Thank you for your questions, Lucas.

Our next question is from Kevin Tracey with Oberon.

Great. So 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 took 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 Haute?

So 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 3 weeks so I think we expect to see the results of that come May 19-ish somewhere in there, give or take a day. So we'll be curious to see how those come out. But really, that's a 1-year auction. And what we're seeing is indications that pricing for multiple years is at, like I said before, prices that we feel will — let's just say, it will cover our fixed cost to the plant, give or take $5 million, right? And that kind of depends on the year. They've gone to a seasonal construct this year. So it's — that's a new twist on the capacity market. But we feel that we feel happy from the standpoint of the capacity payments to some degree. Well, it just kind of ensures that the market signals are saying, look, coal plants are needed and reliability is being talked about more and more and more and becoming more of a concern, which is basically just another way of saying, the grid needs baseload generation that has on-site fuel. And we — that's become an issue this year is that some of the gas plants and some of the markets haven't been able to get fuel to the plant when they need it. So now all of a sudden, there's a lot of conversation in the industry about, well, gosh, on-site fuel, which coal and nuclear plants have is an attribute that is becoming more valuable as other generating sources struggle with that, right? And these attributes have been there all along, but when you start decreasing the fleet, you start seeing the cracks of oh, gosh, the market didn't pay for onsite deal, it didn't pay for spinning generation. And these are attributes that always kind of showed up for free. And now you see the great operators saying, "Well, hey, are we going to start compensating the industry for this because these are attributes that we absolutely need?" So as you have this transition, there's new challenges that are created for that created by that or revealed. And so 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 going to become to our company. And so — and seeing what we feel, it isn't — this isn't just a 1- or 2-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. But early indications are we're seeing indicators that are 5 and 6 and 7 years out that show, hey, this asset is going to be, we think, pretty profitable for quite some time. And that's why you heard us in our last call that we — our Board had approved to extend the capital to invest in ELGs because we feel this plant is going to be needed beyond 2025 and 2028 and beyond. So that could change. Market conditions change. But the direction we're seeing so far is this plan is more needed, not less needed at least by the economic indicators. So for all those reasons, we're very excited.

Okay. And can you put a number on what the total fixed costs of the plant are in a given year?

No, that's not something we've disclosed yet. I mean, at the end, we've only owned this asset since October 22. So we want to make sure that what we project and estimate is accurate. But I think we feel comfortable that capacity today looks to be very, very close to cover all or maybe exceed in some cases, depending on the year of our fixed cost needs. So as time goes on, we may elaborate more on that. But today, we haven't disclosed that.

Okay. And just to make sure I heard you right at the beginning of the answer to the first question. You did in the bilateral capacity contracts sell the capacity for a higher price than you're selling it for to Haute. Did I hear that right?

Yes, you heard me correctly.

Okay. And going in those contracts, so the auction is just for a single year. But 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 on a year-to-year basis?

Well, we don't — we can't — we have the negotiations ongoing and it's always hard to say because sometimes negotiations start out one way and finish a completely different way. So I would say that 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 it was meant to be kind of where everybody sells an incremental amount of capacity. And I think they even want to encourage everyone to either generate their own capacity or acquire that and bilateral agreements. Of course, MISO sees all of these transactions. So they very much know what's going on. What comes out of the MISO auction is kind of indicative and it kind of isn't. It's the first year that we've seen — it's the first year that MISO has had a seasonal construct for capacity. This is the first time the auction has kind of dealt with this new animal. We — I've seen a whole range of predictions of what's going to come out of this auction, which just tells me, nobody really knows, right? So at the end of the day, we know that the reserve margin in MISO, and I think will soon be followed by PJM, these numbers have gotten much thinner. And so as we no longer have great excesses of capacity showing up in the MISO auction, which has caused prices to go materially higher. So for all those reasons, we feel good about the pricing today. And we will see how successful we will be about contracting capacity in the future.

Okay. And then just another clarification. The $30 per megawatt cost figure or megawatt hour cost figure you mentioned in the call, is that just the variable costs, the kind of the fuel and O&M costs, but does it include the CapEx or the other fixed costs? Is that right?

So we'd include our maintenance CapEx in that number. We do not include any future environmental investment that we need to make. So — but from a variable cost point of view, if we were to sell at cost fuel to the plant. And again, this is kind of for hypothetical because there are market rules around how we have to price coal to ourselves. So that can get a little confusing for anyone trying to follow that. So 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, kind of washout and that number is roughly $30 per megawatt hour.

Okay. So that $30 is kind of everything, but the environmental CapEx you're going to have to do for the next couple of years?

Correct. Fuel and so on.

Yes. Got it.

Okay. Last question.

Maintenance CapEx would be in our fixed costs. Our variable costs, we look at that, that is fuel, that is scrubber stone. That is NOx compliance, things like that.

Okay. Okay. And last question. So your comment that you expect to sell 1 million megawatt hours to non-Haute parties this year. That would seem to imply the plant is inventory constrained in the second half of the year. I guess I'm wondering if there is potential upside for that 1 million megawatt hours if you're successful in sourcing more coal elsewhere?

Well, 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; we estimate, based on those prices today, that we will sell an additional 1 million megawatt hours that are unpriced.

The next question comes from Kenneth Pounds with Castlebury Advisory. Brent Bilsland, the CEO, responded that they have considered the possibility of sourcing more coal from other places, which ultimately depends on the price. He mentioned that when analyzing the power curve for 2023 and their obligations to other parties, they estimate that they will sell an additional 1 million megawatt hours that are currently unpriced.

Great job, gentlemen. 2 questions, and maybe you kind of covered it a little better. So 2024, you said 6.5 million to 7 million megawatt hours is what you think you can produce next year?

Yes. You're a little choppy on the voice connection, but I think you said — I think what I heard you say is we plan to produce somewhere around 6.5 million megawatt hours in 2024, and that is correct.

Now what's the nameplate capacity for the plant?

Well, nameplate capacity for the plant is 1,070 megawatts.

Okay. That trend — okay, that translates into how does that you just gave us 6.5%?

Well, $1,700 a day. I mean it translates to about 8.15%.

Perfect. Sorry, 8.1. Okay. And is it possible that — and how much coal will we have to produce for us to try to hit that number?

I'm sorry. So your — the connection is bad; we're just not hearing you.

The next question is from the line of Mike Rybak with Butler Hall.

Just a follow-up on the last question, right? So it's an impressive number you guys can do kind of 6.5 megawatt hours. What drives, I mean because looking at it historically, right, the plant has never really done more than, I don't know, 5.5 megawatt hours, something like that. And obviously, I respect that you guys are coming in and are looking to run it better. But is there something structurally that's changing that gives you guys confidence that you can increase output by 1 million megawatt hours?

Yes. Power prices are considerably higher than in the past. So when you looked at the ratio of fuel cost, we're vertically integrated; Haute was not. And so when you look at the ratio of fuel costs of power prices, we're in a better market today than they were historically. And even if you look at last year, they had pretty strong power prices last year, but they had already kind of begun backing down their maintenance CapEx and those sorts of things because they were going to close the plant, right? That was the game plan. And then we were able to acquire the plant. And so we've begun a process of reinvesting in maintenance of the plant to get it — it wasn't in a bad condition but to get it in a better condition so that we can achieve these higher numbers. So 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? And so all we're really trying to say is, hey, here's what we think today based on the market signals today. So market signals changed quickly for the better or for the worse. But I think the general trend that has been revealed, and we've talked about this in the past. 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 any max generation events, meaning where the grid operator comes out and says, everybody turn on as we're struggling to meet load. And in the trailing 12 months, it's been something like 11x, they've made that phone call. So what we're saying is because there's been such a rapid closing or retirement of baseload generation and a large percentage of that base load 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. So because of that, the smaller fleet that remains has to work harder, right? And so that is what we're seeing in the pricing of the market, and that's what we're trying to use. So we think the opportunity is bigger than it was in the past.

Right. No, that makes sense. What just — what power price I guess, where would power pricing how far down would they have to go for you guys to say 6.5% is not the right number? I mean it seems like relative to the curve today, you could still see power pricing, I don't know, they go down to $40 per megawatt hour. It still seems like that would be achievable.

Yes, we are vertically integrated, which means we could either make no profit at the plant or earn $0.50 profit at both the plant and the coal mine, and in that case, we would still operate. However, I won’t discuss the specifics of that number today. Our main point is that we're at the favorable end of the spectrum. The markets are strong but can change rapidly. Last year, energy markets experienced extreme fluctuations across the board. We're optimistic about the opportunities we see, but we need to be cautious in our projections since we don't have everything contracted yet. Currently, coal and power pricing signals look promising. Our power plant is transitioning from being mostly sold out to having a significant amount of unsold capacity next month, which makes it hard to predict power prices. If the whole year sees mild temperatures in the Midwest, power prices will suffer, but if we have a heatwave, it could be chaotic as the grid struggles. The grid operators have noted that MISO is increasingly relying on PJM for support, but if there are extreme weather conditions in both markets, they won't be able to share resources effectively. We've seen instances where power prices spike dramatically due to these conditions. The market is indicating it prefers to pay a premium to avoid being caught off guard during such events. If power demand drops, that premium may fade, but if extreme weather occurs, the premium will rise. The energy market has shifted significantly from three years ago due to the increased integration of variable generation, which brings new challenges that the power markets must address.

Okay. Just 2 questions, one on Merom one on the core. But so in Q1, so if we just look at your electrical revenue was $93 or so million. You had that $33 million that was a kind of a contract liability amortization. So net of that, it was about $59 million. And then $16 million was about the energy capacity revenue. So the remaining kind of generation revenue is about 43%. I think you noted that you generate about 1,000 megawatt hours. And if you're getting paid $34 per megawatt hour, shouldn't it be $34 million? I was having trouble reconciling why the generation revenue was $43 million.

Because there's capacity at the moment.

Well, he removed those details. I know it's not $9 per megawatt, but we do have adjustments and additional payments based on whether we over-generate for the day when prices increase. I can check on this and email you the specifics. Your assumption makes sense. While we have a rate of $34, we don't receive exactly that amount when we generate excess power. For example, if we bid 900 megawatts for the day and produce 910, the excess power that isn't used by Haute contributes to the difference.

Okay. And then to the question, the first question on the carryover tonnage. You guys signed like 2.2 million tons at $125, I think like the majority of it is in '23. And obviously, you guys haven't specified how much in '24. But I was playing around if I just say, okay, let's just say, 0.4 million tons is in '24, right, at $125. You guys noted that for next year, right, for '24, you have about 2.7 million tons at $51, which includes this tonnage of $125. So in my kind of quick back of the envelope, if it's 0.4 million tons, that implies the rest of the tonnage, the 2.3 in this example is contracted out at a $38 price? I'm just trying to figure out why it's so low.

We can't really comment on our other contracts. However, we have multiyear contracts that come with varying prices. Some of our lower prices stem from coal that was priced 2 to 3 years ago. I don't want the market to focus too much on the specific numbers; instead, keep in mind our average prices shown in the table. When building your financial model, consider our cash flow and future projections alongside the average price, the tonnage we have, our cost reductions, and the volumes we anticipate moving. This will help you reach your conclusions.

There are no additional questions waiting at this time. So I will return the call back over to Brent Bilsland for any further remarks.

Yes. Once again, I think we are very excited about the quarter. We're very excited about 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. So with that, I'll end the call and get to work for next quarter. Thank you. Bye-bye.

That concludes today's Hallador Energy's First Quarter 2023 Earnings Call. Thank you for your participation. You may now disconnect your lines.