Hallador Energy Company (NASDAQ:HNRG) Q2 2023 Earnings Call Transcript May 9, 2023

Hallador Energy Company beats earnings expectations. Reported EPS is $0.61, expectations were $0.16.

Operator: 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. All lines will be muted during the presentation portion of the call with an opportunity for questions and answers at the end. If you’d 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.

Becky Palumbo: 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 estimate 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 at some of those risks and uncertainties that may affect their future results 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 filed 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 and 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. And with that, I’ll turn the call over to Larry.

Larry Martin: 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 equated to $0.67 basic earning per shares 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 times at the end of the quarter. I will now turn over the call to Brent Bilsland, our CEO.

Brent Bilsland: 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 31st, 2023, our debt-to-EBITDA ratio dropped to 1.2 times and our liquidity increased to $36 million. Our coal business saw production increase to 2 million tons. YR costs 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 would 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. However, if the market’s changed in such a way that it’s more profitable to sell our Sunrise Coal to third parties and purchase steel 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. But 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 costs of Merom not covered by capacity payments, including costs such as brick, 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 nine 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 Hoosier, 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.

Q&A Session

Operator: 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. Please proceed.

Lucas Pipes: Thank you very much, operator. Good afternoon, everyone.

Brent Bilsland: Good afternoon. How are you doing, Lucas?

Lucas Pipes: I’m doing well. I hope you’re doing well as well. 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 wondered what the megawatt hour production was at Marin 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.

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

Lucas Pipes: Very helpful. Thank you. And the capacity payments, is that – how should we model that going forward? Was that a lumpy one-off or would that be consistent for the remaining quarters of the year? Thank you.

Brent Bilsland: No, I think that – so 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. And so, the economics of the plant will be fairly consistent from – for the first two months of Q2, we think. And 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, that’s pretty much it, that’s 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 of the capacity, 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 or almost or slightly more than cover, depending on the year we’re talking about, the fixed cost 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 roughly a 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.

Lucas Pipes: Sorry, Brent, could you repeat those last two numbers again for the balance of 2023 and then for 2024? And go ahead.

Brent Bilsland: So, basically, June through December of 2023, we anticipate selling a million megawatt hours, which are currently unpriced.

Larry Martin: In addition to what we have contracted with Hoosier.

Lucas Pipes: That is correct. Very helpful. Sorry. Thanks for the clarification.

Brent Bilsland: And then same for 2024. We have something like a 1.6 million megawatt hours sold to Hoosier. And then we anticipate, something like 5 million megawatt hours 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.

Lucas Pipes: And it’s that power prices or capacity prices or both?

Brent Bilsland: Both. Well, more so on the energy side, power prices.

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

Brent Bilsland: Yeah. 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 usually fairly closely linked to the Indiana hub for market prices. And, it varies by month. Those prices change every day. But, right now the market is pretty robust. And that doesn’t necessarily mean we haven’t, we haven’t 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. 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 it’s, there’s, 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 we would argue 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 two years ago, nobody was talking about reliability. Last year we had a couple people talking about reliability. And today I think, there’s all sorts of public comments from NERC, FERC, PJM, MISO, everyone is talking about, 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 naked or unhedged when we go through these events where generation struggles to meet load, which is happening more and more frequently as base load generation is replaced by generation that cannot be dispatched, does not have an on switch. So, all of that 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 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 2024 if prices hold, which today our thinking is they will.

Lucas Pipes: Very helpful. Thank you. I did something really quickly here back off 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 a million megawatt hours. So, I arrive at about $76 per megawatt hour on the revenue side. Is that the right approach?

Larry Martin: 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. So, there is about 30 some million in that revenue that is just credit because to reverse the discounted contract prices that we sold to Hoosier. 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 revenues. Accounting never makes it easy. So – I think we have disclosed before our contract with Hoosier is $34 a megawatt hour. But, that significantly is less of our business starting June 1st. Hoosier gets all of our power through May 31st. And then, as Brent said, from there on, it’s the power grid runs on a June 1st to May 31st fiscal year. So, we are selling them 1.6 million megawatts out of 7 million that we can 6.5 to 7 million we are going to produce after June 1st.

Lucas Pipes: 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. And I wondered how much of that is for taxed several years, and I wondered how much of that is for 2024? Thank you very much.

Brent Bilsland: Well, I’m not exactly. I don’t know. Yeah, 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 it 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 have.

Larry Martin: 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. 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 it 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 hoop to the Merom Power Plant and converting those to megawatts at a higher price than equivalent at $57.

Lucas Pipes: Got it. So, if I assume 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. So, it leaves a little less than 2 million tons to be sold in the open market for 2024. Is that the right way to think about it?

Larry Martin: And we do have 1 million committed that we are now negotiating prices on. So.

Lucas Pipes: Got it. So –

Larry Martin: 1 million is committed on price, and then we have about a million or a little less to sell.

Lucas Pipes: Very helpful. Would you put the market today for Illinois Basin Coal for 2024?

Brent Bilsland: Yeah. So, again, we are in the middle of negotiations on that. So, we will decline to answer that.

Lucas Pipes: Understood. Fair enough. I look forward to the update on the pricing front. And Brent, to you and the team, continue the best of luck. Really appreciate all the color.

Brent Bilsland: Thank you for your question, Lucas.

Operator: Thank you, Mr. Pipes. Our next question is from Kevin Tracey with Oberon. You may proceed.

Kevin Tracey: Great. So, I suppose we will 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 are 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 are contracted with Hoosier?

Brent Bilsland: So, they were at higher prices than where we previously contracted. I would say that 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. So, we will be curious to see how those come out. But really, that’s a one-year auction. And what we are seeing is indications that pricing for multiple years is at, like I said before, prices that we feel will, let’s just say it’ll cover our fixed cost of the plant, give or take $5 million. That depends on the year. They’ve gone to a seasonal construct this year. So, that’s a new twist on the capacity markets.

But, we feel that, we feel happy from the standpoint of, the capacity payments are, to some degree, well, it just 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 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.

And these are attributes that have been there all along. But when you start decreasing the fleet, you start seeing the cracks of, oh, gosh, that the market didn’t pay for on-site fuel. It didn’t pay for spinning generation. And these are attributes that always showed up for free. And now you see the grid 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, this isn’t just a one or two-year economic case. We’re seeing the market show us signals that look longer dated. We’ll see if they’re real. We’ll see if we can contract there. But early indications are, we’re seeing indicators that are five and six and seven 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 say that we, our board had approved to expend the capitals to invest in the 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 plant is more needed, not less needed, at least by the economic indicators.

So, for all those reasons, we’re very excited.

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

Brent Bilsland: No, that’s not something we’ve disclosed yet. I mean, again, we’ve only owned this asset since October 22nd. 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.

Kevin Tracey: Okay. And 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?

Brent Bilsland: Yeah, you heard me correctly.

Kevin Tracey: 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 doing it on a year-to-year basis?

Brent Bilsland: Well, we don’t, we can’t, we have negotiations ongoing and it’s always hard to say because sometimes negotiations start out one way and finish completely different ways. So, I would say that if we have enough market indicators that we feel that capacity values are robust for multiple years. The MISO auction is a market where, it was meant to be 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 in 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, it’s indicative and it 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.

It’s the first time the auction has, 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. So, 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. 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.

Kevin Tracey: Okay. And then just another clarification. This, the $30 per megawatt cost figure, or megawatt hour cost figure you mentioned in the call, is that that’s just the variable costs, so the fuel and O&M costs, but doesn’t include the CapEx or the other fixed costs? Is that right?

Brent Bilsland: So, we include our maintenance CapEx in that number. We do not include, any future environmental investment that we need to make. So, we have come out and said, hey, we’re going to invest in technology to meet the Effluent Limitations Guidelines standard. 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 and what the compliance costs may or may not be. So, but from a variable cost point of view, if we were to sell at-cost fuel to the plant, and this, again, this is 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 , plus maintenance CapEx, all that stuff wash out? And that number is roughly $30 per megawatt hour.

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

Brent Bilsland: Correct. Fuel and so on. So —

Kevin Tracey: Fuel, O&M, and maintenance CapEx. Got it. Okay. And last question.

Brent Bilsland: Maintenance CapEx would be in our fixed cost. Our variable cost, we look at that that is fuel, that is stone, that is, NOX compliance, things like that.

Kevin Tracey: Okay. And last question. So, your comment that you expect to sell a million megawatt hours 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 million megawatt hours if you’re successful in sourcing more coal elsewhere?

Brent Bilsland: 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 million megawatt hours that are unpriced.

Kevin Tracey: Okay. Great. Thank you very much.

Brent Bilsland: All right. Thank you.

Operator: Thank you, Mr. Tracy. . The next question comes from Kenneth Pounds with Castlebury Advisory. You may proceed.

Kenneth Pounds: Hello. Good morning. Great job, gentlemen. Two questions, and maybe you covered this a little bit earlier. So, 2024, you said 6.5 to 7 million megawatt hours is what you think you can produce next year?

Brent Bilsland: Yeah, you were 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.

Kenneth Pounds: Now what is the name plant capacity for the plant?

Brent Bilsland: Well, name plant capacity for the plant is 1,070 megawatts.

Kenneth Pounds: Okay. That translates into – how does that translate to what you just gave us, 6.5?

Larry Martin: Well, 1,070 a day, I mean, translates to about 8.15.

Kenneth Pounds: Perfect. Thank you. Sorry. 8.1. Okay. And is it possible that – and how much coal do you have to produce to try to reach that number?

Brent Bilsland: I’m sorry, sir. The connection is bad. We’re just not hearing you.

Kenneth Pounds: Okay. Thank you.

Brent Bilsland: Thank you.

Operator: Thank you, Mr. Pounds. The next question is from the line of Mike Rybak with Butler Hall. You may proceed.

Mike Rybak: Hey. How you doing? Thanks for taking my questions. Just to follow up on the last question, right, so it’s an impressive number if you guys can do 6.5 megawatt hours, million megawatt hours. What drive – I mean, looking at historically, right, the plant’s never really done more than, I don’t know, 5.5, 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 a million megawatt hours?

Brent Bilsland: Yeah. Power prices are considerably higher than in the past. So, when you looked at the ratio of fuel cost – we’re vertically integrated. Hoosier was not. And so, when you look at the ratio of fuel cost to 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 began, backing down their maintenance CapEx and those sorts of things because they were going to close the plant. That was the game plan. And then, we were able to acquire the plant. And so, we began 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 change quickly for the better, 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 had any max generation events, meaning where the grid operator comes out and says, everybody turn on, because we’re struggling to meet load. And in the trailing 12 months, it’s been something like 11 times they’ve made that phone call.

So, what we’re saying is, because there’s been such a rapid closing or retirement of base load 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. These assets 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. And so that is what we’re seeing in the pricing of the market. And that’s what we’re trying to communicate. So, we think the opportunity is bigger than it was in the past.

Mike Rybak: Right. No, that makes sense. What power price – I guess, where would power pricing have to – 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 can still see power pricing – I don’t know – they go down to $40 per megawatt hour. It still seems like that would be achievable?

Brent Bilsland: Yeah. So, I mean, we’re vertically integrated. So, there comes a point where we would make zero profit at the plant – or make $0.50 of profit at the plant and $0.50 of profit at the coal mine. So, arguably, theoretically, in that scenario, we would still run. Where exactly that number is, it’s not – that’s not something we’re going to get into today in that analysis. But I think our point is, is that we’re at the opposite end of that scale. The markets are pretty robust. They do change quickly. We saw 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.

It’s been very volatile. But – and the opportunities 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. So, it’s this double-edged sword for us of trying to indicate how good we think it can be without overstating our position. So, what we’re saying today is capacity signals look good, coal pricing signals look good, power pricing looks excellent as well. So, 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. We’ll see what the power prices bring. If the entire year is 65 degrees in the Midwest, power prices will be terrible.

And it just – there won’t be that much load to meet. If we see 110-degree heat indexes, look out. It’s going to be crazy, because 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. But 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.This is where we see these extreme events where power prices go to, a couple thousand dollars an hour, a megawatt hour. And that’s – so the market is saying, well, if more of those type of events are out in the future because there’s a lack of generation, we’re going to pay a premium above the price of, a gas generator or a coal generator because we don’t want to be caught.

When the tide goes out, you find out who’s naked. That’s the old saying. The market is saying we don’t want to be caught in that scenario. So, what we think we see is the market saying, well, 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, extreme temperatures, that power premium will increase. This transition is – 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. We have forced a lot of variable generation into the grid, and that creates new challenges. And the power markets are now forced to pay to try to solve those challenges.

Mike Rybak: Okay, just two questions, one on the Merom, one on the core. But so in Q1, I want to share this. So, if we just look at your electrical revenue was 93 or so million. You had that 33 million that was a contract liability amortization. So, net of that was about 59 million. And then 16 million was about the energy capacity revenue. So, the remaining 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?

Brent Bilsland: Because there’s capacity payments –

Larry Martin: Well, he took those out. I think 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. So, I can look at that and send you an email of where we’re at exactly. Because 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 megawatts for the day and we produce 910 for the day, then we do get that excess power that doesn’t go to Hoosier. So that could be – that will be most of the difference.

Mike Rybak: 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 these tonnages at 125. So, in my 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 like contracted out at a $38 price. I’m just trying to figure out why it’s so low.

Brent Bilsland: Well, I mean, I guess we can’t really speak to what all our other contracts are or aren’t. I would say this. We went from a period of time, we have multi-year contracts. And so, we have prices that were low, we had prices that were high. Some of those lower prices came from coal that we priced two, three years ago. And so, I don’t want the market to get hung up on, well, exactly how many of these hundred, like we’re showing you in our table what our average prices are. So, I think if you’re trying to create your model, 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 of production has been, here’s the volumes that we think we’re going to move. I think you’ll get there. I think you’ll get to where you’re trying to be.

Mike Rybak: Okay. Well, thank you so much. Best of luck.

Brent Bilsland: Yeah, I appreciate the questions. Thank you.

Operator: Thank you, Mr. Rybak. There are no additional questions at this time, so I will turn the call back over to Brent Bilsland for any further remarks.

Brent Bilsland: Yeah, once again, I think we’re 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.

Operator: That concludes today’s Hallador Energy first quarter 2023 earnings call. Thank you for your participation. You may now disconnect your line.