HNRG - NASDAQ

Hello, everyone, and welcome to the Hallador Energy Third Quarter 2023 Earnings Call. My name is Emily, and I will be coordinating your call today. [Operator Instructions] I will now turn the call over to our host, Rebecca Palumbo. Please go ahead.

Thank you, Emily, and thank you, everybody, for joining us today. Yesterday afternoon, we released our third quarter 2023 financial and operating results on Form 10-Q that is now posted on our website. With me today on this call is Brent Bilsland, our President and CEO; and Larry Martin, our CFO. After the prepared remarks, we will open up the call to your questions. Before we begin, please note that the discussion today may contain certain forward-looking statements that are statements related to the future, not past events. In this context, forward-looking statements often address our expected future business and financial performance. While these forward-looking statements are based on information currently available to us, if one or more of these risks and uncertainties materialize or if our assumptions prove incorrect, actual results may vary materially from those we projected or expected. For example, our estimates of mining costs, future sales, legislation or regulations. In providing these remarks, we have no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, that may be required by law. For a discussion of those risks and uncertainties that may affect our future results, please review the risk factors described from time to time in the reports we file with the SEC. As a reminder, this call is being recorded. In addition, we will have an archived webcast of this earnings call on our website. We encourage you to ask questions during the Q&A, and if you are on the webcast and would like to ask a question, you will need to dial in to the conference line. That toll-free number is 1833-470-1428, access code 224373. And with that, I will turn the call over to Larry.

Thank you, Becky, and good afternoon, everyone. Before I begin, I want to define adjusted EBITDA, which we define as operating cash flow less the effects of certain subsidiary and equity method investments, plus bank interest, less the effects of working capital changes, plus cash paid on asset retirement obligation, reclamation, plus other amortization. For the quarter, Hallador incurred net income of $16.1 million, which was $0.49 a basic earnings per share or $0.44 per diluted earnings per share. For the year, net income was $55 million, $1.66 earnings per share, $1.52 diluted earnings per share. We had adjusted EBITDA for the quarter of $35.9 million and, for the year, $105.2 million. We decreased bank debt by $12.5 million for the quarter, $23.5 million for the year. Our funded bank debt as of September 30 was $61.8 million. We had letters of credit totaling $11.2 million. And our net funded bank debt was $59.2 million, which is funded - or bank debt less cash. Our leverage ratio, which is defined as debt to adjusted EBITDA, was 7.1 times at September 30. Did I say seven point - 0.71 times for the quarter. I will now turn the call over to Brent to review the quarter and beyond.

Thank you, Larry. First, I would like to thank the Hallador team for their hard work and dedication on creating another successful quarter. As I have highlighted in our previous quarters, our goals of increasing profitability, increasing company liquidity and reducing balance sheet leverage remain paramount to how we operate as a company. This quarter’s results show our continued progress towards these goals. Our net income of $16.1 million for the quarter helped build on our record net income of $55 million for the first nine-months. And our continued record operating cash flow of $79.5 million over the nine-month period has allowed us to invest $48.7 million in capital expenditures to improve our efficiency and reliability at both our mines and our power plant. We made continued progress on our goal of improving our balance sheet by repaying $23.5 million of debt during the first nine-months of the year, $12.5 million of which was during the third quarter. This further reduced our leverage, as Larry said, to 0.71 times, while we increased liquidity to $66.4 million as of September 30. On October 2, we successfully amended our credit facility with PNC Bank, which we accounted for as a debt extinguishment. This amendment is important as it extends the maturity of our credit facility into 2026. During the third quarter, high coal sales prices, coupled with large coal shipment volumes, led to record coal revenue. Our well-contracted sales book supported our revenue growth despite operational challenges increasing our cost per ton during the quarter. We chose to relocate 57% of our coal units of production during the third quarter and into October to better - to obtain better geologic conditions. This led to higher cost and decreased production during this time frame, but is resulting in overall production improvements following the moves, which we expect to continue. During the quarter, we shipped 2.1 million tons of coal at an average price of $56.43 before intercompany eliminations. We produced 1.6 million tons in the quarter at $46.54 per ton before eliminations. Leading to margins of $18.89 per ton during the third quarter before eliminations. We expect an average price of $54.30 per ton on the remaining tons to be shipped this year. On the power side of the business, intercompany coal sales from our Coal division to our Power Plant division, increased the average variable cost per megawatt hour to $40.03 per megawatt hour, an increase of $9.98 per megawatt hour over the prior quarter before eliminations. We set the price of coal we sell to ourselves based on third-party market indicators that we review from time to time. Cost per megawatt hour were $23.49 on a consolidated basis. As the marketing price fluctuates, we expect to see these types of variances in each side of the business. During the quarter, we produced 1.3 million megawatt hours. We are excited about the progress we are making in our forward power sales capacity book. During the quarter, and in the time leading up to this release, our Power division was successful in securing $325 million of energy and capacity sales across multiple years, as reported in our Form 10-Q filed last night. This morning, we received a signed agreement for an additional $41 million of capacity and revenue over the years 2024, 2025 and 2026, bringing this number of total sales up to $366 million. These sales are important as they create a profitable foundation for our Power division over the next five-years, with sufficient energy sales at - or excuse me, with significant energy sales at $56 per megawatt hour, and capacity prices approaching $220 per megawatt day. Now we get a lot of questions concerning how an investor should think about Hallador now that we have added a power division. To add clarity, we included a detailed section - we included a lot of detail on Section 3 of the overview of the MD&A outlining our sales of coal, power and capacity through 2028. At a high level, I think about our business as such. We produce seven million tons of coal annually. Just over four million tons is sold to outside customers and almost three million tons is sold to our Power division, Hallador Power. The reference table will show that, over the next five-years, 54% of the coal that we plan to sell to outside parties is already committed to those parties and 73% of these commitments are priced at an average price of $52.60 per ton. Our year-to-date cost per ton to produce coal was $43.25. The other three million tons assume that we will annually produce 6 million-megawatt hours at our power plant. Now there are rules about how we price this coal to ourselves and the accounting around this can be confusing to follow due to the internal eliminations. However, the price that is chosen for the coal that we sell ourselves only determines how much profit or loss is allocated to our Coal division or our Power division. Ultimately, what matters is how much profit is made at Hallador based on our cost structure. During the third quarter, our consolidated variable costs at the plant was $23.49 per megawatt hour. As stated in previous quarters, we use our capacity sales to cover the majority of our fixed costs at the plant. We have sold and we expect, with the capacity prices that we are seeing, that to continue. We have sold approximately 27% of our future power through 2025 at $34 per megawatt hour, roughly a $10 margin based upon that cost structure. But in this past quarter, we have sold 3.3 million megawatt hours for the 2026, 2027, 2028 years at $56 per megawatt hour, which is roughly $32 per megawatt hour profit margins based on today’s cost structures. These sales have us very excited about the profit potential for Hallador Power. Now that doesn’t mean there won’t be operational challenge such as the one we experienced on October two when we had an unplanned transformer outage in one of the generators at the power plant. The transformer has since been replaced, and the event will cause us to miss a net two to three weeks of output from one of those two units. I want to reemphasize, I am very excited about the future of the company, especially as I look to the power sales through 2028, what we are seeing through increased pricing from our recent power PPAs, coupled with strong capacity demand and pricing. With a solid book of business that we are now showing and the steady supply of coal from our mines. I am incredibly pleased with the progress that we are making towards leveraging the opportunities that drove our decision to acquire the power plant. As I said at the start of my comments, I’m encouraged by the quarterly results and the continued progression of Hallador as a company. And with that, I will open up the call for questions.

Before we go to questions, I want to clarify one sentence here. Our shipments were 2.1 million at $65.43 for the quarter, for an $18.89 per tonne margin.

Thank you, Larry.

[Operator Instructions] Our first question today comes from the line of Kevin Tracey with Oberon Asset Management.

Great. The first one is just to clarify what I thought you just heard you say about the outage at Merom. So in the 10-Q, there is a note where it says the unit isn’t expected to be back into service for the second half of December. But I thought I heard you say that the outage was only two to three weeks. So I guess, was it - are we kind of missing 2.5 months or two to three weeks of this unit?

Yes. Let me clarify that. So the unit was already scheduled to get on a scheduled outage from November 1 to December 27. That is something that we schedule with MISO six to nine-months in advance, and we bring in outside contractors to do routine maintenance on the unit. So that was planned. The unit went down basically a month early due to the transformer. And so we have sped up part of the outage work to begin some of that work that we could do in October, which means, instead of the unit coming back online, it is December 27, it will probably come back online a week or two earlier than it was previously scheduled. So net-net, we are going to lose this unit - one of the two units for two to three weeks longer than was expected and planned for.

Cross your fingers the power prices are higher in December.

Okay. And going forward, will there be - do you expect any impact on MISO’s accreditation of the plan for purposes of future capacity revenues or are you hoping that won’t be material?

Yes. I think every time you have a forced outage - so accreditation is a rolling three-months - a three-year process, right and so they are looking at your performance history during that time frame. So things that help your capacity rating are - we acquired a plant that was scheduled for shutdown. So some of that maintenance was let go. And we are spending additional monies this year and next to kind of get the plant back in what I would call tiptop shape. And so where that helps you on accreditation is we are seeing higher output numbers than when we took over the plant a little over a year ago, right. So as you get newer and better and refurbished equipment on the plant, you are able to achieve higher performance. That is to the good side. The bad side is, every time you have an unscheduled outage such as we had with the transformer, that counts against you in accreditation. And then I would say, thirdly, we still see MISO making tweaks and adjustments to their accreditation process. They have not finalized those rules, and so we can’t ever be 100% certain what comes out of that. Do we get more accreditation? Do we get less accreditation? It is always hard to say. So all we can do, and what we have done is, as of our last accreditation, which was eight hundred and - I mean it is on a seasonal basis, but I think on average, our accreditation was 860 megawatts. That is what we are basing our numbers on. So when we show you, hey, here is how much capacity we have sold as a percentage of the plant, it is based on an assumption that our accreditation is 860. But that number could go up or down based on our accreditation from MISO.

And I want to emphasize on one thing Brent talked about. Being down also depends on when. If you are down in a low demand period, it doesn’t count against you as much as if you were down during a high demand, say, minus even 20 degrees or something like that in the winter when there is a lot of demand for electricity. So us being down in October in a mild season may not count as much against us as - and we may get more upside when we come back on in December. That is total speculation, but it is...

Odds are we are going to have colder weather in December than we had in October. Power prices theoretically would be higher. So it may not be as - we may be trading 4 mild weather weeks for 2 cold weather weeks. We just don’t know and we won’t know until we get there.

Understood. Okay. And then, so with these power sales agreements you have entered in. So you have sold about one fourth of your planned generation for the next several years. Can you talk a bit more about how high you want to go in terms of selling power forward as a percentage of your expectation? And then how are you managing the risks there, or if the plant were to have an unplanned outage and you have agreed to supply power at certain prices, if you find yourself long the power market? So how are you kind of managing risks when you are thinking about entering those agreements? And if you could touch on how high you are hoping to go in terms of forward sales.

Yes, good question. So far to date, everything that we have sold on the power side is plant or unit contingent, meaning that we sold the power, and if we fail to perform, we do not have to go out and buy that power. We don’t have to cover, right. We just simply are not shipping those electrons to the customer and they either have to do without it or they have to go buy them elsewhere. But that is not on our accounts. So I think as excited as we are about our sales, on a risk-adjusted basis, we are extremely excited about that. I’m going to look to see what opportunities are for - these are bilateral agreements. These are not exchange hedges. On an exchange hedge, as a firm power sale, we would have to cover in that scenario. And so we want to make sure that we have a lot of liquidity if we do that type of hedging. And so part of our process and what we have talked about here is we want to make sure we get our balance sheet as healthy as possible, get our liquidity as high as possible, and then we will look to the market to see if there is hedges that we want to - additional hedges that we’d like to layer in.

Okay. And then on the mining cost per - sorry, go ahead.

Yes. I was just going to say, we certainly prefer the bilateral agreements on a risk-adjusted basis.

Got it. Okay. And then on the mining cost per ton, I think heading into this year, the hope was that we would see an improvement over 2022’s $37 per ton. We have obviously seen costs rise quite a bit from there. Can you talk about sort of what went wrong versus your expectations? Was it just and general inflation or an issue with the geology? And you made some comments about improvements you are seeing from some changes you are making. Can you help set expectations on where you think your mining cost per ton will be for 2024?

So on the production outlook, it is pretty - we have seven units - seven individual production units underground. I think it is pretty typical in any given quarter for one or two of those to be struggling. What was unusual about this quarter is we had four units struggling. And we - sometimes that catches you at a time that is a little out of sequence to be moving. So you fight that for a little while. And then finally, ultimately, you come to the decision of we need to shut the unit down and move it. And there is just lost time in production when you do that, particularly out of sequence like we did this quarter and into October. So, very unusual to move four units at any given quarter, but that is what we did. And that is ultimately had an outsized factor on why our costs were the highest they have ever been in any quarter in the history of the company. So, disappointed by that. All I can say is we have moved those units, and I’m pleased with the productivity that I’m seeing to date out of those units. So we expect our cost structure to be better in the future.

Okay. Are you willing to put out a number on where you think the cost structure will be. Can we get into the 30s again?

I think that I think we will - we have seen inflation. So I think probably in 2024 - gosh, some of that is going to depend on what the production levels are at each mine. But I think you will see us back into the low 40s, upper 30s.

Okay. And then on the CapEx, so your fourth quarter guidance implies that the full year CapEx will come in about $10 million than your original budget. And it looks like all of that, I guess, all of that delta from your original guide is coming from the Coal business. Can you talk about where you think CapEx will end up kind of on a normal basis for the coal business going forward? And then do you have any update on the affluent project at Merom and kind of where you are thinking the CapEx budget is going to look like next year?

I will handle the coal part, and then Brent can answer the affluent question. But for the coal plant, we just had some - with our moving things around the 57% we moved, we had some mine development we had to do. And then we had some equipment that is going to come on at the end of the year that we thought was going to be in the next year. So that is our $10 million difference. Going forward, I think our plan is $35 million for CapEx for the coal plant. Do you want to talk about ELG.

Yes, on ELG. So the EPA has proposed a new rule, that has yet to go final. So we are waiting to see where they ultimately end up. And we expect them to finalize that rule in this coming spring. And so that ultimately will decide what we do and the exact timing and compliance dates to meet that rule. Our Board has approved $45 million to spend on that. We still feel comfortable that that will meet where we think the EPA is heading with that rule and their most stringent standard. But we will wait to see where they end up on the final rule before we comply with that. So that is delaying the expenditure of some of those dollars until we know exactly what the EPA wants.

Okay. And then last quick one here. On the last call, your latest update on your target of getting to basically 0 net debt was the second quarter of next year. Is there any update to that guidance?

Yes. I think the higher cost that we experienced this quarter is going to push that out at least a quarter and into the third quarter of 2024.

Our next question comes from Kevin Pounds with Castlebury Advisory.

Kenneth. I think you mentioned in the last call that you were looking for you might benefit from hot summer or surges in demand in the summer. Did you experience that for the power plant?

No, we really saw a pretty mild summer. I think we had two weeks of hot weather. So we saw good pricing during that time frame. But the balance was somewhere - from a power pricing perspective was fairly anemic. So we are still kind of waiting for more colder days or hotter days, but we don’t like 65-degree days from a business perspective, right?

On the West Coast here, there has been refineries closing. Are there some other older power plants that are in your area that might be closing that would tighten up the market or have you seen anything like that?

Yes. We did just have another power plant that closed last week in MISO

Yes. Sure you definitely improved earnings visibility. And I know you have made similar comments before, which sounds impressive. We have had a lot of reports lately about these renewable projects being too expensive and not delivering certainly the margins that people had wanted. Finally, you said you had four of the seven units that struggled. Are some of those units may be not going to be too high cost, if we keep seeing cost creep all over the country, not just you guys, obviously, with inflation and fuel and so forth?

Yes, I thought it was interesting, there is been several mining companies that have reported before us, and it seemed like everybody had a tough operational third quarter. I’m not really sure why that is. I don’t know if it was something about the - a lot of humidity that came out of the mines. Has it cool down or if it was just coincidence. But certainly, everybody has seen cost pressure due to inflation, but I really think the majority of what we had going on in this particular quarter and into October was geologic and specific to our mines. And I think that we have solved that problem. And I’m sorry that the quarter wasn’t better from an operational cost point of view, but I hope - I think, we have fixed the problem.

Our next question comes from Jason Lustig with J. Goldman.

Just wanted to say thank you for increasing the disclosure in the contract table, really helps, I think as another caller said, just better understand the long-term economics of the company. So, appreciate that. As I have thought more about this table, I think we are getting a sense for what the future revenues of the company can look like, the three different revenue streams. We have a reasonable sense of the coal costs per ton, the fixed costs we have talked about in the past at the plant. One thing that I’m struggling a lot with and would appreciate trying to better understand is the variable costs per megawatt hour excluding fuel at the plant and how we should think about that over time.

Well, look, I mean, fuel is the majority of it. I think we have come out and said that during the quarter on a consolidated basis, variable costs, including fuel and nonfuel, was $23.50 per megawatt hour. So I don’t think at this time we plan to break out what our nonfuel expense is. Quite frankly, I think we have got enough numbers that our goal was to not confuse everyone. Our goal was to create as much clarity as possible. And that is why we spent a lot of time on that table I referenced, in an effort to try to get everyone to understand, right, because it gets very confusing when you start pricing coal to yourself and you have these intercompany eliminations, which is all GAAP, it is all the way it is supposed to be. But we are trying to clarify that, that, hey, at the bottom line, it is just a great earnings potential at the power plant. And we hope everybody gets as excited about that as we are, particularly when our most recent pricing particularly on a risk-free basis, since it is unit contingent, it is quite profitable. And so anyhow, I appreciate your compliments on that. We are probably not on this call going to get into what our nonfuel costs are at this time.

Okay. Okay. I appreciate that. If I flip to the coal operations segment of the 10-Q, I see this as $37 million in sales to the Merom plant that are eliminated in consolidation. And I would love to try and triangulate and better understand how I can reconcile that number with the $40.03 per megawatt hour cost at a variable cost at Merom and the $22.49 consolidated number. And maybe that can get us most of the way there for those who are on the outside and still confused.

I’m not 100% sure I understand that question.

I’m trying to just - we can do our own math, I guess, on the outside to try and allay any confusion. But I am trying to figure out I guess, what was the cost or the price of the coal that was transferred and what is the right number? Is it 0.5 million tons, which I think I saw somewhere else in the 10-Q. Is there some other number that I should be using for this quarter? I can...

So everything - and I will give you - I mean I’m not - you guys can do the math, but here is the numbers. We sold coal to ourselves for $75, which is in the Q. So we have to eliminate that. And then our costs were 40-some - I can’t remember off the top of my head where they are at in the Q. But then our costs for the quarter were $46 I think. So that profit has to be eliminated as you sell the coal to yourself. Now we did burn, but it is not just what we sold in sales, it is what we actually burned. There is some sitting in inventory that got eliminated as well.

[Operator Instructions] Our next question comes from [Tom Kerr] (Ph) with Saks Investment Research.

I think most of my questions were just covered. A couple of quick ones. As you guys continue to generate more free cash flow, refresh my memory if there is any restrictions on returning capital to shareholders through dividend, share buybacks, et cetera.

Now at our current leverage ratio, we have no restrictions.

Okay. Great. And then lastly, you guys have indicated in the past that you may be looking for other power plants for acquisitions to add to that side of the business. Is that still good? Is that still a plan or any opportunities out there you can mention?

Well, nothing we can list specifically by name. We are always looking, and we think Hallador is in a unique spot to potentially take advantage of those opportunities. So certainly, we are looking.

Our next question comes from Lucas Pipes with B. Riley Securities.

Just a few quick ones for me, First, Brent, in terms of struggling on the coal side, what exactly is meant by that? What happened?

I think you have units that run into bad roof. It could be could be that you have got presence of water or sandstone coming in close contact or close location to the coal. And when we get that sometimes you can fight through that and get to the other side of it. And other times, you have to back up, move over. Sometimes you back up, move over, back up, move over a second time. And then there comes a point where you just say, you know what, I’m going to move to a different portion of the mine and tackle this from a different angle or a different point of view. Moving over and attacking it again, that is pretty common. That happens. Major moves to a different area, that is pretty uncommon, and particularly for four units in one particular quarter. So I think we want to say that it was significant. It was unusual. And we think that that is behind us.

Were all those four units working in close proximity when they encountered these difficulties?

No.

And the areas that you moved out of, are you going to move back towards them in due course or would you say, for the foreseeable future, it was just too tough, you don’t want to go back there?

Yes. I mean sometimes you just move around to the other side of it, right. There could be a good area of coal that can be a year or two of good mining and you just need to access that from a different location. So I don’t want you to lead you to believe that we are abandoning large portions of our reserve. That is not the case at all. We are just attacking it from a different point of view.

Got it. Okay. That is helpful. And then I want to go back to your comments earlier on hedging versus bilateral agreements. And it sounded like there are certain advantages on these bilateral agreements. Does it come down to force majeure provisions? Is that really the difference?

No. I mean it is pretty common to have either firm sales or unit contingent sales and a bilateral agreement with a particular customer is a very bespoke agreement. And I would almost argue that no two agreements like that are exactly the same. Whereas, hey, if I’m just jumping on ice and buying or selling a power contract, that is a very cookie-cutter, fixed agreement, it is different. And it takes a lot more risk, right. You can get a margin call if you are on ice. I can’t get a margin call for my customers. We have to have contingent power. So from a risk perspective, I think we have put ourselves in a really good - what we say is a good foundation of business. I don’t know that we can sell all of our power under that particular format, so we will see. All we are saying is that we had great success in this particular quarter, and we have got a great team that is out trying to get in situations that is both good for our customer and good for ourselves.

And Lucas, to expand on that a little bit. Think of it as I mean, we say unit contingent, but we have guaranteed a certain percentage for the year. So if the unit goes down, we don’t have to deliver on a unit contingent basis. And power could be very high that day and we don’t get penalized. But then some of that, depending on the percentage, we may make up later at our contracted price. So you said force majeure, it is not really force majeure, but kind of.

Got it. So the kind of the legal term would be there kind of, I think you said, unit contingent, right?

Correct.

That is helpful. And then yes, I really appreciate the disclosures. A quick question there on Page 18 of the Q. Contracted power revenue, that line shows 2024 98.05 million. That is pretty clear. The item immediately underneath it, how is that derived exactly? Can you walk me through that, the 43.34, the revenue per megawatt hour? I clearly doesn’t assume the $6 million. So I kind of struggle a bit to back into that.

78% of 6 million. So Lucas, that is contract, what we have contracted for the year, which is 78% of six million.

Got it. Okay. So it is not based on the six million, you make the assumption you are running at you said 78% up to six million?

Well, it is what we have, we don’t have six million contracted. We have six million we can provide. So the 98 million is what we have contracted.

Yes.

That is total capacity and energy.

Correct. And the line underneath the 43.34 million, what -.

How much revenue we are going to get on our contracted megawatts.

But you have only 1.6 million contracted now?

But that includes capacity and power.

Got it. Okay.

I think what we are showing here is -.

[Indiscernible] divided by 78% of six million, 32, plus $34.

Yes, maybe we can take that off-line, but I appreciate it. I think I know where this is going. But maybe one quick follow-up. You have only 1.6 million of output contracted, right.

Correct.

And so I mean, the capacity payment, you have capacity payments, but you can still generate revenue on top of that though.

Absolutely. So we have 4.4 million megawatt hours of power that we can still contract.

Our next question comes from [Roger

Congrats on a strong quarter despite some obstacle, guys. My question is, I have not had a chance to delve into the Section 3, you said it is related to power in general, is an exciting new market. Am I reading the release just posted, one of the tables that in 2024 you have got 27% of your power priced? Is that correct, from the non-GAAP table that was provided in.

At $34, yes.

Yes, that is correct.

So you have got 83% left to, potentially, there would be some windfall times in there, if possible, right. When you get some extremes either way, as you said, that is pretty exciting?

That would be 73%. So basically, what we are saying is yes. We have got 27%, let’s just call it fourth around that. We have got a fourth price and we have got another two third or three fourth that we are open to, we bid into the market every day. And the prices can be high and prices can be low and prices can be so low that we take the unit offline. But we think we are heading into winter. And that typically historically has been some of the better pricing. So we will see what December, January and February bring.

But also, we have 78% of our capacity sold for next year, which if we sell 100% of our capacity, we think that will cover the majority of our fixed costs.

Correct. Okay. And a real general question you may or may not be willing to answer, but kind of a basic high-level question. Are you finding a very strong correlation to the nat gas market for power as it is with coal?

Yes. I mean there is a lot of gas generation in MISO. And so if gas prices are cheap, those gas units can produce cheap power, and we have to compete against that, to a certain point, because once load exceeds gas generation, then coal is going to compete against coal or if gas prices go high as they did in 2022, then you will see coal potentially dispatch in front of gas and gas will take the upper end of the market. But pricing today on gas is pretty cheap.

Right. The coal-to-gas switching thing and vice versa, right, it is always in play, right. Sorry, one last question on this topic perhaps. Regarding, again, the power market, are you mostly correlated to the Chicago hub, MISO hub, and even the nat gas in some way or is it more of like this summer with record heat throughout Texas or in the South for upwards of a month, were you able to capitalize on that this past summer or is it more of a regional, say through Chicago, should we think of it in those terms?

Yes, it is definitely more important what the weather is Indiana through Chicago. And the gas price is closest to us matters the most, which, in that case, Chicago Citygate is one marker that we look at for sure.

You weathered a bad summer that way. Chicago was as mild as it is been forever, right. And we are right south of you [indiscernible] right. I mean I -.

Well, I think, look, we are very encouraged in that where there is a lot of new industrial demand showing up in the Midwest. Europe has had basically an energy crisis since the Russian invasion of Ukraine. And that is causing a lot of re-onshoring industry. I was with politicians yesterday who more than one said, look, Indiana has a great business climate, we are not sure if we have enough people, and we are not sure if we have enough power. And so Hallador being long power likes to be in that scenario. We like where we are at. There is going to be some volatility to our earnings because we do have a large open power position, and that is subject to market movements. That would be great. And there is a high end, there is a low end. But I think, by and large, on average, will do really, really well. That is why we like the base of business that we are putting under it with our forward contracted sales. And we are encouraged by the most recent pricing that we saw at $56 a megawatt hour for multiple years.

Those were all the questions we have for today. So I will turn the call back to Brent for closing remarks.

Yes, I want to thank everyone for taking the time to dial in and having interest in Hallador. And we are excited, very excited, about the future and what the Power division is finally starting to show everyone its capabilities of. And we look forward to more exciting quarters to come. Thank you.