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spk00: Thank you everybody for joining us today. Yesterday afternoon, we released our full year 2022 financial and operating results on Form 10-K, which is now posted on our website. With me today on this call is Brent Bilsen, our president and CEO, and Larry Martin, our CFO. After the prepared remarks, we will open the call up to your questions. Before we begin, please note that the discussion today may contain certain forward-looking statements that are statements related to future, not past events. In this context, forward-looking statements often address our expected future business and financial performance, while these forward-looking statements are based on information currently available to us. If one or more of these risks or uncertainties materialize, or if our understanding assumptions prove incorrect, actual results may vary materially from those we projected or expected. For example, our estimates of mining costs, future sales, legislation and regulations, in providing these remarks, we have no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, that may be required by law. For a discussion of some of those risks and uncertainties that may affect our future results, you should review the risk factors described from time to time in the reports we file with the SEC. As a reminder, this conference call is being recorded. In addition, a live and archived webcast of the earnings call is also available on HALADOR's website. We encourage you to ask questions during our 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 844-200-6205, access code 724924. And with that, I'll turn the call over to Larry. Thanks, Becky, and good afternoon, everyone.
spk03: Before I get into our review of operating results, I want to define adjusted EBITDA. We define this as operating cash flows, less the effects of certain subsidiary and equity method investment activity, plus bank interest, less effects of working capital period changes, plus cash paid on ARO, reclamation, plus other amortization. So for the year ended 2022, we ended with net income of 18.1 million or 57 cents per basic earned share, and our diluted earnings per share was 55 cents. The diluted earnings per share for us is if the converted debt was converted to equity. Our adjusted EBITDA for the year, is 56.2 million. Our bank debt decrease was 26.5 million. And our bank debt at the end of the year was 85.2 million, excluding letters of credit of 11 million. So we had 85 million of borrowed debt, 11 million of letters of credit. Our net bank debt at the end of the year was 82.2 million. And our leverage ratio, which is adjusted EBITDA debt to adjusted EBITDA was 2.05 times. I'll now turn the call over to Brent Bilsen for his review of the year and beyond. Thank you, Larry.
spk04: Building upon my comments from the third quarter investor call, the full year 2022 was transformational for Halidor. As the market price for coal approached all time highs, we were able to capture significant market opportunities through forward contracted coal sales of more than 2.2 million tons at an average price of $125 per ton. We delivered a small percentage of these tons in 2022, are contracted to deliver the majority in 2023, and will continue with longer term deliveries through 2025. to fulfill these new profitable obligations. We invested substantially in both operations and headcount growth to quickly expand our coal production capacity from approximately six million tons annually in 2021 to as much as seven and a half million tons in 2023. We expanded coal production capacity by adding more units at our Oak Town mining complex opening a small surface mine pit near Freelandville, Indiana, and moving our ace in the hole production to a small surface mine pit near Petersburg, Indiana, known as Prosperity. Freelandville and Prosperity production began in Q3 of 2022. Volumes from these new pits are expected to be higher cost. We will continue to evaluate the productivity of these mines in connection with market conditions to determine the appropriate operational balance. Our average coal sales price increased from $39.51 per ton in 2021 to $45.64 per ton in 2022, and will be approximately $58.70 per ton in 2023. Various factors, including inflation, operational challenge and new hire onboarding and training impacted our costs of production and margins. However, we closed the year with fourth quarter margins of $10.41 per ton and full year margins of $8.35 per ton compared with 2021 margins of $7.35 per ton. Looking at costs, Much like the rest of the world, we experienced and are experiencing increasing costs to produce. Our average coal cost increased from $32.16 per ton in 2021 to $37.28 in 2022, with fourth quarter costs just above $40 per ton. As we start to realize additional efficiencies from the experience Our added headcount continues to gain. Fewer production challenges and increased production. We expect these costs to levelize out or improve throughout 2023. Additionally, in Q4 of 2022, we completed the acquisition of a one gigawatt Mirum generation station. The transformational impact of acquiring Mirum is not just limited to adding new revenue generation opportunities for our business. While we expect sales of both capacity and energy to help drive growth, Merrim will add support to our coal business by providing flexibility for up to 40% of our coal production to capture the greatest value between the energy and coal market. Starting in 2024, We anticipate shipping up to 3 million tons of coal annually from our mines directly to Merham. The close proximity of the mines to the plant, about 20 miles, enables real-time adjustments that should promote additional efficiencies for both business segments. Moreover, at Merham, we anticipate 3 million tons of our coal will produce approximately 6.5 million megawatt hours that we anticipate selling into the MISO wholesale energy market. We expect to utilize funds from third-party sales of the annual capacity accreditation of MIRIAM to cover a significant portion of the annualized fixed costs of the plan. While the capacity market will fluctuate over time, we believe that at current capacity Merrim provides a low cost option to act as the highest value market for our coal production. The vertical integration also provides true optionality in terms of how and when we sell our coal and energy. In some instances, if coal prices remain high, it may make sense to divert coal away from Merrim and into the open coal market. In other situations, it may make sense to increase our shipments to minimum and sell additional energy in the wholesale energy market. In either case, flexibility is a key benefit that Halador did not have prior to the acquisition. We also recognize the challenges of operating a coal-fired generation station. Due to the volatility of power prices, our earnings will be lumpy, but we believe on the whole that our profit potential has significantly increased. Utilizing a strategy that incorporates offers into the day ahead power markets allows us to capture a significant portion of this potential while also limiting the outside risk. Additionally, for us to operate MERIM beyond 2025, there will be required investment in environmental controls prior to the end of 2025 that could exceed $45 million. Based on the present state of the energy markets, the declining capacity reserve margins of the grid, and increasing frequency of grid emergency events, we expect power markets to remain elevated. Over the course of 2023, we'll be transitioning into a company with much higher long-term profit potential, but one which will likely experience periods of great volatility. Demand is the downside risk of these volatile periods. We continue to focus on reducing bank debt. In 2022, bank debt was reduced by $26.5 million, bringing the balance owed at the end of fiscal 2022 to $85.2 million. As of December 31st, 2022, our liquidity stood at $32.1 million, and our leverage ratio has dramatically improved to 2.05 times. Subsequent to year end on March 13th of 2023, we executed an amendment with our credit facility, which converted 35 million of the outstanding revolver to term debt with final payment due in March of 2024 and extended maturity of the remaining 85 million revolver capacity to May of 2024. Looking at CapEx, our 2023 capital expenditure budget is $69 million, of which $35 million is maintenance CapEx. Of the $69 million, roughly half is associated with coal and the other half associated with power. Now, I'm going to flip the call back over to Larry Martin, our CFO, and asked him to walk everyone through the purchase accounting associated with the Merrimack position.
spk03: Thanks, Brent. Although the only consideration how Adore paid for the power plant was roughly $15 million, which consisted of $5 million of inventory, $3 million of transaction costs, and $7 million of assumed reclamation liabilities for the ash disposal, We accounted for this as an asset acquisition as required by generally accepted accounting principles. We entered into the purchase agreement with Hoosier Energy in February of 2022 and closed the transaction on October 21st of 2022. The energy markets were volatile during this period. Thus, in the time between signing and closing the PPA, and closing, the PPA was below market and both the coal purchase contract and the coal inventory were below market. So under generally accepted accounting principles, we accounted for this as a purchase accounting. This resulted in a $185 million liability adjustment for the PPA contract and a $34 million asset adjustment for the below market coal purchase contract and inventory. These two large adjustments along with the $15 million consideration and some smaller GAAP adjustments resulted in $188 million of consideration given under GAAP purchase accounting. 23 million of the 185 million PPA contract liability was recorded to revenue in 2022. Of the $160 million, Remaining of the liability, $88 million is in current liabilities on our balance sheet and will be recorded to revenue in 2023. Seventy-five percent of this will be by May 31st. Of the $34 million associated with the coal purchase contract, $3.6 million was included as expense in 2022. The remaining $30 million is recorded as a current asset and will be reversed to expense by May 31, 2023. So while approximately $58 million of 2023 earnings will result from this GAAP accounting treatment, our Free Cash Flow EBITDA reporting debt covenants and taxable income will be unaffected by these non-cash adjustments. I will now turn the call back over to Brent for closing comments.
spk04: Well, I'd like to open up, that ends our prepared comments, and I'd like to open up the call to any questions from our investors.
spk02: Thank you. If you would like to ask a question, please press star followed by one on your telephone keypad. If you would like to withdraw your question, please press star followed by two. And when preparing to ask your question, please ensure your device is unmuted locally. Our first question today comes from Lucas Pipes from BeReilly Securities. Your line is open.
spk09: Lucas Pipes Thank you very much, operator. Good afternoon, everyone. My first question is in regards to liquidity. the amount of liquidity the business needs on an ongoing basis. How would you frame that up? So you have the maturity not until 2024, so lots of time there, and then I would expect you to generate healthy EBITDA in 2023. But if you could maybe frame up how much of cash generation should go towards debt versus how much cash you'd like to keep on the balance sheet, would appreciate your perspective on that. Thank you.
spk04: Yeah, thank you, Lucas. I think our goal is you can never have too much liquidity. Our deep plan is to try to get this company net debt free sometime around the end of first quarter of 2024, and then have a, credit facility and cash on our balance sheet that, you know, hopefully is in the zip code of $100 million. So I think that's what we look to do with our company over the next, you know, 12 months roughly from today. And I think that with contracts in hand that we have and then, you know, this year, the majority of our earnings are from our coal division with the power plant providing minimal earnings. And then in 2024, it looks to us that, you know, we'll be taking a much greater percentage of our coal to the plant. So the profitability of the plant will come into focus at that time. So I think that answers, I hope that answers your question.
spk09: That's very helpful, and sorry if I didn't catch everything there. You said that in 2023 there will be much of a contribution from the power plant. Did I hear that right, or could you expand on that?
spk04: Yeah, so if you look at the majority of our business, we have sold power to the seller of the plant, primarily most of the output of the plant through May of this year. And then that PPA reduces to about 20% of the output of the plant thereafter. So we will begin to ramp up some of our coal shipments to the plant But the majority of our profitability will come from the coal division in 2023. When we get into 2024, we anticipate taking as much coal as possible, hopefully up to 3 million tons to Merrill and convert that coal into electrons. We think that judging by the forward power curves today, Mind you, power prices change every hour of every day. But looking at the curves that we're looking at today, that looks to be the most profitable thing to do. So that's the signals that we're seeing today. And what we tried to outline is that the capacity markets today are robust and should materially cover you know, most if not all the fixed costs of the plant. So we kind of view it as we essentially have a very low cost option with the plant to either take our tons to the third-party sales market, which is traditionally what we've done, or take those tons to Mirum and convert them into electrons, which looks to be considerably more profitable to do today. We'll see what the market brings. We saw the markets change very quickly in 2022, which affected why we chose to, if you went back to our prior calls, why we chose to sell such a high percentage of our coal to third parties. And part of that was because we didn't, we hadn't closed on the plant yet. So there was some, you know, we were not a hundred percent certain we could close on the plant. There's always challenges to that. So it was the, you know, on a risk adjusted basis, it would made the most sense to contractually sell 2023 tons to third parties. Whereas 2024, that strategy appears today by the market signals today that it will that it will change and we'll sell less to outside and more to ourselves.
spk09: Got it. Thank you for that. What is the forward price for power for this market for 2024 today?
spk04: Yeah, that's a proprietary number so we're not disclosing that. Okay, okay.
spk09: That's helpful. And just because I tried to look through the 10K, and apologies if it wasn't immediately obvious to me, but the contribution of Marin to EBITDA in the fourth quarter, where did that come in?
spk04: It was roughly $5 million later than the exact number.
spk03: It was like 5.5 million for Merrim for the, yeah, for 2022. So we had like 56.2 million adjusted EBITDA, Lucas, and about 5.5 of that was from the power plant.
spk09: Got it. Okay. Super. And then... Thank you very much for this. I'll do one last one and turn it over. When I look at your contract book, 7.5 million tons for this year, and then I think 2024 through 2027, you have 7.3 million tons. Can you share how much of the 7.5 and the 7.3 respectively is earmarked for merit?
spk04: Well, again, I think Our goal is to take as much coal as possible to America. We think that converting fuel into electrons is a value add. It should be nine times out of ten our best market. There are some unique things that happened last year. Last year's market may have been one out of the one out of the 10 for a small window of time. So we chose to take advantage of that. But I think nine times out of 10, we'll try to take up to 3 million tons of our 7 million tons of production due to the mural. And like I said, forward curves are certainly supportive of that today. We have not chosen to sell a lot in the forward curve market as of this moment, about 20% of our production. In the balance, we are currently in position to sell in the day ahead market. So we're still kind of...
spk03: Let me add there, so Lucas, in your question on that table, the 7.5 and the 7.3 and beyond, there's zero Hoosier or Merrim sales in there. That is all third party sales to third parties.
spk09: Very helpful. Really appreciate the caller. I'll jump back in queue for now. Thank you both.
spk02: Thank you, Lucas. Our next question comes from Kevin Tracy from Oberon Asset Management. Your line is open.
spk07: Great. Thanks for taking my questions. The first one's on the price of coal tons, I guess, beyond 2023. In past 10Ks, you've disclosed the price position for the next two years. In this latest 10K, you haven't put out the price for 2024. Footnote in your 10K where you note that the performance obligation related to price tons is 593 million. So if I do some quick math, you know, I'm coming to the 3.3 million price tons that are beyond 2023 are at an average price of roughly $46 a ton, which is obviously a pretty big step down from what you expect this year. So I'm hoping you could comment on if that math is right and given natural gas prices are awfully low today, if it's fair to expect the coal price you receive from third parties next year to take a step down.
spk04: All right. Well, I'll try to dissect that. There are several questions in there. I think your math is generally in the right zip code. But what's a caveat to that is the dilemma we have is if we take, you know, here 40% of our coal production to the merum generator and we convert that into electrons and we price that at the day ahead curve, the pricing today looks very robust, right? And we may do that, but we have not done that yet. So on one hand, we say, well, we've got a home for it, but we haven't pulled the trigger on that sale. There's some reasons for that, right? There's, you know, if you make a forward sale on power, you're obligated to perform, and there can be significant penalties for not performing. And one of the things that we're seeing in the So we're trying to look at that and make sure that we do that in an appropriate way that we are maximizing the profitability of the plant without taking too much downside risk. And what I mean by that is, so if you looked at in February of 2021 in Texas when they had the five-day outage with storms You saw several power producers who had sold, say, $50 per megawatt power were hit by that storm and couldn't produce and were forced to cover that $9,000 a megawatt hour in the Texas market and were bankrupted pretty quickly. Now, we're in the MISO market. Texas is an ERCOT. max limit is legal limit is $3,500 a megawatt hour, which means, you know, if you were caught in that event, you would go bankrupt slower. But, you know, so we're working on ways that we can lock in the profit potential for some of the plants while at the same point in time, limiting our downside risk in the event that the plant can't or wouldn't perform at that precise moment. And what we're seeing is if you look at, you know, one of the trends that's going on in the industry is generation that has an on switch, and I would argue onsite fuel, coal, nuclear, is being prematurely replaced with generation that either doesn't have an on switch, wind and solar, or doesn't have onsite fuel, natural gas. Those are basically the three options that the market is replacing generation with. And what we're finding is if you go back in MISO to prior to 2016, they had zero MaxGen events, right? They had all this excess capacity of generators they could turn to when demand got high. Well, now we're seeing those reserve margins, or another way of saying that is excess generation capacity is gone, which is why the capacity payments of the plant now are high enough to cover a significant portion of the fixed cost of the plant. And back to 2016, we saw zero MaxGen events. In the last 12 months, we've seen 11. And these are events where power prices are hitting just astronomical numbers, right? So there's a balance as everyone tries to figure out this trend in the grid where is, you know, it's these super high price events are happening with greater frequency. So are you better to lock in margins ahead at, say, $50 per megawatt hour or $40-some per megawatt hour? Or are you better to have your generator less sold and, you know, ramped up and ready to go during these max-gen events where we're seeing, you know, power prices in the hundreds of dollars or sometimes even thousands per megawatt hour? So that's what we're trying to balance. And that's why we say, you know, gosh, man, if we are less sold on the power side, we think our earnings could be really wealthy, right? Yeah, so that's what we're trying to balance. So I hope that answers your question.
spk07: Okay. And on the capacity auction side of things, do you still expect to be able to fully participate in the auction that's coming up shortly, right, for I think the 12 months that start June 1st? So the auction... I'm talking related to the 68% of capacity that you don't need to sell. Are you able to fully, I guess, bid that into the auction that's happening shortly?
spk04: Well, first of all, let's not confuse capacity with energy, right? So if a utility out there wants to buy a gigawatt of power from the grid at any given time, any given hour of the year, they have to supply MISO either in-house or purchasing from a third party like us. a gigawatt of rated capacity and this year MISO went to a seasonal construct. So our plant's accredited capacity has various accreditations for winter, spring, summer, fall. And we sell a significant portion of that to third parties and then what isn't sold typically will go to the MISO auction, which is March 28th. And the results of that will be announced a week or so thereafter. You know, whatever you didn't sell in the third party, somebody will essentially buy small amounts there, right? But capacity has been, is the thing that is, because the accreditation has been reduced on a lot of the renewables, right? They haven't performed well in these, particularly winter events. Wind hasn't performed well in the summer and solar hasn't performed that well in the summer. And now we're seeing where gas is not performing well in extreme cold events. I mean, to quote Claire Moeller of MISO, who's the president and chief operating officer of MISO, his comment is, you know, in regards to the last two winter events, extreme events is gas is now zero for two, right? And so we've seen TJM come out and their market monitors say hey, we don't think, we are recommending that gas plants that don't have now two transmission lines should not be, unless they have two transmission lines, it shouldn't be accredited in any capacity. So that could be, that could substantially change how tight the capacity markets are, which improves those pricing, which we're using that to cover our fixed costs. Now on the energy side, that's not, To my knowledge, that's not typically sold in the MISO auction. MISO auction is a capacity auction. The energy side, you know, you can either sell, first of all, every electron has to be sold to MISO and every electron in that region has to be purchased from MISO. But you can have essentially a side letter agreement or contract or PPA with, like we do with the seller of the plant, where we say, look, you're going to buy your electrons from MISO, we're going to sell our electrons to MISO, but we're going to true up with each other at a set price. And what I'm saying for that is, is post May of 23, we've got about 25% of the output of the power plant contracted through a PPA through 2025, December of 2025. We're evaluating if we want to do more of that. But at this time, our company for 2024 will look where it has a greater percentage of its sales in the spot market, which will make our earnings, though we think more profitable, lumpier.
spk07: OK. And on that PPA with Hoosier, so when you struck the contract, or when the deal closed in October, like natural gas was more than $6. It's since fallen a lot. So I imagine the futures prices for power have also fallen significantly. So the question really is you put this big liability on the balance sheet because back in October, the PPA was underwater. Today with natural gas prices much lower, I imagine the PPA is much closer to market prices. So am I right in thinking that? And could you share maybe what the price or what is the price in the PTA for Hoosier and is that price fixed through 2025?
spk04: Yeah, we're not disclosing that price. then we have, you know, confidentialities in those agreements where we cannot at this time. You know, maybe once we have more of those, we may choose to aggregate that, but at this time, it would be too obvious. So you're absolutely right, right? So you set a price, you know, quite frankly, the price was set prior to even signing, right? I mean, that contract was negotiated for quite some time. It was announced. right around Valentine's Day, we closed October 22nd. So in the meantime, we had an invasion of Ukraine, which said kind of triggered, you know, somebody said, did it trigger the energy crisis? I would say it revealed the energy crisis. We think the energy crisis has been building for quite some time. We don't think that has changed. The only thing that really happened is when you saw the invasion of Ukraine, you saw governments come out and purchase every BTU they could get their hands on. And so, particularly in Europe, right? And you've seen other countries now say, well, gosh, I think it was Malaysia that, no, I'm saying that wrong, Pakistan. Pakistan, they had relied heavily on natural gas plants that import LNG Europe bid up the LNG. They couldn't afford the LNG. So now you see Pakistan building 10 gigawatts of coal-fired power plants because they say, look, we're not going to allow ourselves to get single fuel concentrated again and put ourselves in that position. I would say Europe very much still has an energy crisis going on. They got bailed out because they bought very aggressively heading into winter which created a shortage here last summer. And then Europe had weather patterns that were 30 degrees above normal this winter. And so here they overbought and then demand didn't show up. And that's put out a cooling effect short term on energy prices and power prices. But long term, they still are sanctioning the largest gas exporter in the world, the second largest oil exporter in the world, and the third largest coal exporter in the world in Russia. And I think that we're seeing that. I read a stint last night saying that, you know, the budget of Russia has been hit by about 50% now with all these sanctions on its energy markets. Well, that means that the economics to produce a BTU in Russia has declined significantly and I think you'll see production come off there probably permanently as US energy companies and western energy companies leave that country. That's got to be replaced and those markets will turn back to the US. So I, you know, I think there's a temporary downturn here in those markets. To be fair on the coal markets, people ask, you know, what's the price of coal? There's no transactions really happening right now in the coal market. That's one of the advantages of us having the power plant is the electricity market is a very liquid market. It trades every day in big volumes. So it definitely, we've improved the liquidity of the revenue stream of our company by having the Merrim asset. So we will continue to evaluate what is the best way to price electrons in a risk weighted fashion so that we don't put our shareholders at risk. And one of the ways we play defense on that is you're gonna see our balance sheet very much deliver over the next 12 months. We already went from the end of the third quarter to like 3.5 something to 2.05 at the end of Q4. At the end of Q1, we drop off our Q1 2022 quarter, which was lousy, and we replaced that with our first quarter of 2023, we expect that to further significantly deleverage our balance sheet as we continue to pay down debt. That's one of the ways to play defense is to have very little debt on our balance sheet, and that's the position that we're trying to get ourselves in.
spk07: Okay. The last question, can you give us a sense of what the capacity factor of Merum was in the fourth quarter during the period that you owned the plant and what you expect there going forward? Thanks.
spk04: So we had some scheduled outage in the fourth course. I don't know that that would be a very leading statistic. And this year, again, what month are we talking about? Right now, both units are running at min load. So we're operating. What will happen later this year? remains to be seen. It really kind of comes down to how much heat will we see in July and August? If we had this plant last year in July and August, it would have been incredibly profitable. So we'll see what the market brings. If we're taking... Okay, thank you very much. Yeah, thank you.
spk02: Our next question comes from John Moore, a private investor. Your line is open.
spk06: Great. Thank you so much. And this is a remarkable acquisition that you made here of this Merrim power plant. And I guess my question is, are you, you know, there are a number of power plants in Indiana that are going to be shut down. Are you considering acquisitions of more power plants?
spk04: Yeah, I think we would always take, we would always consider additional power plants. We'll just have to evaluate each one of those opportunities as they come. That being said, I think there's a significant portion of the U.S. coal fleet that will retire over the next decade. And so we think that they will be, you know, more opportunities to look at similar transactions to the MARAM transaction. But, you know, I can't tell you when and I can't tell you where.
spk06: We'll just have to evaluate those when they come. Great. And then the last question is the, I see that the power purchase agreement expires in 2025. And, you know, I had understood that it was sort of going to, you know, May of 2020. three was gonna be an important dropdown in the percentage of the power that you agreed to sell to Hoosier. I thought I had read a disclosure here that you had agreed to sell 70% of the capacity in 2025, up to 2025. Did I misread that? I haven't been able to reconcile those two numbers.
spk04: You misread that. So we have a hundred percent of the energy stole of the plant through May of 23 to the set from the seller. And then it drops down to 20% of the energy output starting in June of 23 through December of 25. We chose not to sell any power beyond there because we have to comply with ELGs if we want to run the plant, which is the environmental piece of it. So that up to 45 millions of environmental expense we will have to invest that money if we wanna run the plant beyond 2025. Now, if we make that decision to do so, then we feel that the plant is in environmental compliance with all environmental rules that exist today. Well, it doesn't mean the rules won't change, but we feel the plant will be in good shape from that standpoint. And that investment would come over a handful of years, so it's one of the things that were disclosed.
spk06: And then I read in the breakout of your electric operations in 2022 that you sold $66 million worth of, you had $66 million of revenue, and you recorded $31 million worth of income, but I assume that was The difference between that and the 5.5 million that you disclosed was just an accounting difference in the contracts?
spk03: That was the result of the GAAP accounting treatments we had to do on the liabilities and assets that I explained in the purchase accounting for the power plant. The 5.5 million was EBITDA and those adjustments were not included in EBITDA. Great, thank you. That's my final question.
spk02: Our next question comes from Mike Ryback from Butler Hall. Your line is open.
spk05: Hey, guys. Thanks for taking my question, and congrats on doing well in a very tough backdrop.
spk04: Thank you.
spk05: So I guess my question, yeah, I just wanted to dig in a little more on the power plan. So you guys did $5 million of EBITDA in the quarter. What was the free cash flow associated with that? And then I guess take it a step further, if that's sort of a good run rate for 23, right, so take five, multiply it by four, that's $20 million. I mean, if you're doing, let's say, $35 million of CapEx, it looks like it's going to be, you know, free cash flow negative to the tune of $15 to $20 million in 23?
spk04: So I don't think that it's fair to look at a partial quarter, right? We did not own the plant for a full quarter. They had scheduled outages in that quarter. So it didn't generate the entire quarter. We're telling you that we've got significant, you know, a hundred percent of the plant sold at agreed upon price in through May of 2023. And then we materially open up, which means the plant's performance will be based upon what is the price of power when we get to those months. We do have, we are spending heavily on the plant for both maintenance capex, realize the seller, had announced in January of 2020 that they were going to close the plant. And so, you know, there's some catch-up maintenance that has to be done with that plant. I think on a going forward basis, once our maintenance is caught up, we anticipate the maintenance CapEx being somewhere in the $18 million a year range. So, and there will be money spent this year to comply with the ELG environmental regulation to extend the life of that plant. We have to begin building some of those structures in 2023, 2024, so that they're in place by the end of 2025. So, you know, we kind of view it as, yeah, we're spending Are we spending more? Will the plant be cash flow negative this year? That's to be determined because that will be determined by what is the power price on the unsold portion of the plant. So I don't think looking at fourth quarter EBITDA is that indicative of future EBITDA of the plant.
spk05: Okay. That's helpful. So if we think about sort of, I guess, normalized, you know, I think you talked about 24 being a contribution year. You know, I don't have the future curve in front of me, but, you know, as it stands today, and obviously it's subject to change, could go up, could go down. But as it stands today, if you think about the future curve in 2024, when factoring in more of a normalized CapEx environment, right, the 18 million you just cited, you know, how do we think about sort of that normalized free cash flow generation of the plan today of the plans in 2024 based on the forward curve today?
spk04: Yeah, so I don't have a number. I don't have a guidance number for you because we haven't quite put to bed what our sales position would be. I think that the fact that we have committed to invest in ELG, which is up to a $45 million commitment, To me, that is a way of saying that we're signaling to y'all that, look, what are our options? Our options are don't make that investment, close the plant at the end of 2025 and sell coal on the open market. And what we're saying is where we see power prices at today, where we see power prices going is it fully supports the investment, right? If the cashflow positive investment, or we wouldn't make that decision. And the thing that's tricky is it's really easy to look at the math and say, well, gosh, you know, if gas is this price and a gas plant can produce an electron at this price, then that's where the power market should be. And what the problem is these extreme events, no one wants to be caught short in the extreme event. So we're seeing that to us that's putting an elevated price on the power market because it's just so punitive to be caught in these extreme pricing events, which are happening with more frequency, just looking at the past data. And when you look at, you know, the United States is looking to retire half of its coal fleet in the next, within the next 10 years, we think that's a lot of generators that have onsite fuel that are suddenly not going to be there. And that is going to change the fundamental fabric of the power market because the new generation has different attributes. But the one that's missing from everything that's being built is onsite fuel storage, right? you can't turn on the renewables, and gas doesn't store fuel on site. And the performance that we've seen of all of those assets in these storm events is not good. So we think that makes the value of our asset go up with each additional retirement that we see because the market will, over time, we believe, continue to pay us an equal amount or higher amounts for the attributes that we see today. So I get that it's a little frustrating that we're not, you know, saying, all right, we're gonna make X amount of money per quarter for the next 10 years at this number, because we just haven't locked that in. So we're not willing to make that statement. What we're saying is we think the potential is dramatically higher for our company, but because we're gonna sell more in the spot market earnings are going to be much lumpier, right, because we're seeing dramatic price differences for a megawatt hour in the month and a shoulder season month versus a summer or winter month. Now, this winter was mild, but we're seeing the power curves hold up better than we thought because I think the market is so afraid to be got short because of what we've seen in Winter Storm Elliott and Winter Storm URI where pricing peg legal limit. I mean, real-time market in MISO on December 23rd hit $3,500 a megawatt hour in all eight zones, right? So when you take a power plant such as ours that realistically puts out 960 megawatt hours or megawatts per hour you can start to see the revenue potential of such a plant. So that's what we're comfortable saying today. I hope as we continue to develop our strategy and additional forward sales positions, we'll say more about that and can give better guidance. But today, we're not in a position to give forward guidance on the profitability of the plant, only to say that we are convinced and we are investing in the plant so that it can be here for many years to come.
spk05: Okay. If I can just ask that question a different way. I mean, obviously, you know, at $58, which is where you're contracted for 2023, that's a, you know, that's a very healthy margin for you guys. And you're probably incentivized to, you know, not sell them to the plant. What is that what is that sort of price of indifference, right? Like, is it, you know, at $50, at $45, you know, you might see actually more of your volumes go into the plant rather than the wholesale market? I don't know, maybe you can give a range, but I'd love to just understand kind of that point of indifference.
spk04: Well, it changes. You know, the forward power curves will tell you, hey, look, we see people out here willing to contract or a megawatt hour in July that might be a very different price than what they would do in, you know, April, right? And so when you say, well, what price are you indifferent, that is a calculation between what are we seeing in the power markets and what are we seeing in the coal markets. We had announced in February of 2022 that we would acquire the Miram generator. And we felt we had a very high probability of closing on that transaction, even though it was subject to various government approvals, FERC being the slowest or longest lead time of those approvals. So during that period of time, we saw the coal markets, multiple customers willing to pay, you know, an average price of $125. That was an average price. There were different prices in that range for 2.2 million tons, primarily in the 2023 year. So we felt that that pricing on that day was very close to or exceeded the value that we thought we could forward contract for on the power side. So we chose to sell a lot of tons to third parties and reduce the amount of tons that we plan to take to the Marin Power Plant in 2023. I can't, there's no set number, right? It was just look at both markets in that snapshot of time in which one has the highest risk adjusted return. And on that particular day, it was the coal market. I expect the coal markets to win that analysis, you know, one out of ten times, maybe. It could be more like one out of 50 times. I don't know. Going forward, we really think that, again, the majority of the time it's going to be the power plant that wins that argument because there's a value add, right? I would argue that it was a panic pricing, but yet, panic pricing in the energy markets is created by disruption, right? So we still have this ongoing issue with the Russian invasion of Ukraine. Could that be further escalated? I mean, we saw Russian planes have a collision with U.S. drones here earlier this week. That could escalate things. What would that do to energy markets? saber rattling to some degree between the United States and China. I personally, as a US citizen, hope that cools down, but those are the type things that can be very disruptive to energy markets and lead to that, what I would call panic pricing that may lead to our coal markets exceeding the value of our power and energy markets. I don't think that will happen the majority of the time. but we just saw it happen. So we'll see what happens going forward. That being said, we're just seeing more and more events that lead to extreme pricing. We, again, think that the Ukraine, that the energy crisis that went on in Europe last summer, you know, the Ukraine invasion revealed that. It was there all along. We saw, you know, demand increasing for BTUs and supply not increasing. Look at the, it's kind of telling if you look at the Illinois basin response to this extreme pricing, right? We really haven't seen a huge production response by the industry, right? I mean, I think production came up 10% as an industry to prices quadrupling. So we think that that, you know, because that response isn't there like it's been in the past, you know, we think we could see more times of a significant increased pricing power. The other thing that's going to happen is today you have a fairly balanced, you know, a significant amount of coal generation and a significant amount of gas generation. And so as gas prices get high, coal will start to dispatch in front of gas and the dispatch curve. If gas prices get low, coal gas will dispatch in front of coal. If you have less gas coal generators over time, when gas prices get high, you're not gonna see switching to coal generation because there is no coal generation, right? So to me, there's this price cap that we have on gas is somewhat being removed by the retirement, the premature retirement of these coal-fired generators. So the markets are changing because we have this rapid transition going on. And then the other thing that's happened is because power prices have gotten so uncertain and so expensive in Europe, I think we're seeing a significant transfer of the industrial, European industrial base is looking for a home And by and large, it's coming, you know, a significant portion of that is coming to the United States and Mexico, which puts further demand along with electric cars and that sort of thing for more power generation that's got to be, you know, powered and fueled by something. So all that's along the same, the trend is moving our way. Thank you for your question.
spk02: Our next question comes from Kevin Pounds from Castleberry. Your line is open.
spk08: Yes. You're entering a new business. Do you retain the staff from the power plant or hire additional people to help you run it efficiently? And the second question would be, you're implying that you're going to be facing less competition from other plants as other ones close, but are you going to have competition on pricing or are you, you know, you referenced this organization, MISU, I guess, that they make a deal with a group of utilities. Is that correct?
spk04: So MISO is the Midwest Independent System Operator. Right, MISO, yeah. Yeah, and that's a region of 15 states and one Canadian province. Our power generator is in the Zone 6 of MISO located in Indiana. So I'm sorry, I answered the last part of your question. What was the first part of your question?
spk08: The first part is we made a significant investment. Have you retained the staff that was working for that plant, and are you hiring additional people to help you optimize its production and its costs and so forth?
spk04: Yes. So we retained all the people at the power plant. We did not acquire probably about 12 people at the seller's corporate office. We retained the same firm that runs the day ahead power desk that Hoosier had. And then we hired CAMS as an independent contractor to technically, they employ the employees of the plant and help oversee running that plant. The plant manager of Mirum is still there. He's done a great job. And the staff of Mirum is doing a terrific job. We just wanted to make sure that we had CAMS as, you know, they're experts that run over 30 gigawatts a generation in the United States, you know, there to offer their expertise and insight and experience. So all that has really gone very well And we're pleased with the performance of both the retained people and camp.
spk08: Great. And then on the coal side, other smaller coal operators have had significant problems with transportation, and you're looking to increase production. Do you feel good about how you're working with the railroads, et cetera?
spk04: Yes. I think there was a shortage of transportation in 2022. I think that is being alleviated here in 2023. So less concerned about transportation today as we were six, nine months ago.
spk08: Great. Thank you.
spk02: Thank you. We have a follow-up question from Lucas Pipes at B. Reilly Securities. Your line is open.
spk01: Yeah, thank you, operator. This is actually Nick asking the follow-up here. I believe a question was asked earlier related to the price Hoosier is paying through 2025, and I'm just seeing in the 10K here, so I want to clarify that You know, I'm reading that Howdor shall sell and Hoosier shall buy at least 70% of the delivered quantities through 2025 at a price which is $34 per megawatt. Am I confusing this with something else or is this the contract price? Thank you for any color.
spk03: So when you're reading the 70%, when Brent says that we sold 20% to Hoosier, from 23 beyond, so we have to deliver 70% of that 20% to stay in contract. So that's our minimum. So it's available. So we sold 20% of the power, it's available, but the minimum we have to do per year, I believe, is 70% of that 20%, if that makes sense. Correct.
spk01: No, that's clear, Larry. No, thank you for clarifying that. I appreciate that. And then I just wanted to ask one more, just kind of on cost expectations for 2023. I believe in your prepared remarks, you said that you do expect costs to come down. Would you be able to put some numbers around that? How, you know, and maybe the cadence of costs throughout the year?
spk04: Yeah, I think we've seen our productivity numbers for Q1 improve and I think we'll see commodity price, you know, steel, limestone and other things like that, diesel. Some of that pricing has come down in the market but it hasn't, you know, our suppliers have contracts too, right? those prices don't step down immediately. I think we'll start to see some commodity input price back off throughout the year, right? As our vendors hedges roll off and those prices eventually flow through or discounted prices eventually flow through to us. So that's why we feel comfortable that We believe our cost of production will be improved going into 2023, or at least levelized. You know, last year was kind of a crazy time where we saw schematic price increases. First of all, it was twofold. One, you had commodity input prices. And second of all, everyone in the industry was trying to ramp up to take advantage of the increased prices, right? The high margin business. And so it got very difficult to get supplies, you know, things like roof bolts that you run out of roof bolts or you run out of glue for the roof bolts and production stops period, right? And it just seemed like there was a run on a different item every week that has calmed down, right? So the industry is, you know, taking its foot off the gas a little bit as coal inventories have increased, which has taken the pressure off all the supply lines. So we're seeing pressure come off the supply line. So I don't think our vendors will be able to demand the pricing they were able to demand last year. Plus their costs will reduce, which eventually flows through to us as their commodity hedges get repriced at lower prices. So that's why we think from a cost perspective, we think things are trending in a better direction.
spk01: Got it. Well, that's good to hear. Brent, appreciate all the color and continued best of luck. Thank you, Nick.
spk04: I won't throw too much at Lucas for having you ask the last question of the call on St. Patrick's Day while tournament basketball is ongoing. So I hope you're allowed to have a green beer later today.
spk02: This concludes our Q&A. I'm going to hand back to Brent Bilson, CEO, for any closing remarks.
spk04: I want to thank everybody for their continued interest in Halidor, and I hope it came across today that we are very excited about the position of the company today and where it is heading. And I thank you all for your time, particularly when there are other things competing for everyone's attention, such as basketball today. So thank you, and look forward to talking to you all next quarter.
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