Hallador Energy Company (NASDAQ:HNRG) Q4 2022 Results Conference Call March 17, 2023 2:00 PM ET
Becky Palumbo - Investor Relations
Brent Bilsland - President and Chief Executive Officer
Larry Martin - Chief Financial Officer
Conference Call Participants
Lucas Pipes - B. Riley Securities
Kevin Tracey - Oberon Asset Management
Mike Rybak - Butler Hall
Nick Giles - B. Riley Securities
Hello, and welcome to the Hallador Fourth Quarter 2022 Earnings Call. My name is Elliot, and I'll be coordinating your call today. [Operator Instructions]
I'd now like to hand over to Becky Palumbo, the floor is yours.
Thank you, Elliot, and 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 Bilsland, our President and CEO; and Larry Martin, our CFO. After the prepared remarks, we will open the call up to your questions.
Before we begin, please note that the discussion today may contain 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 Hallador'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 member is (844)-200-6205, access code 724924.
And with that, I'll turn the call over to Larry.
Thanks, Becky, and good afternoon, everyone. Before I get into our review of operating results, I want to define adjusted EBITDA. We had defined this as operating cash flows, less the effects of certain subsidiary and equity method investment activity, plus bank interest, less effect 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 $0.57 per basic earned share or/and our diluted earnings per share was $0.55. 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 layers 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 2.05x.
I'll now turn the call over to Brent Bilsland for his review of the year and beyond.
Thank you, Larry. Building upon my comments from the third quarter investor call, the full year 2022 was transformational for Hallador. 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 6 million tons annually in 2021 to as much as 7.5 million tons in 2023. We expanded coal production capacity by adding more units at our Oaktown Mining Complex, opening a small surface mine pit near Freelandville Indiana.
And moving our Asean-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 $58.7 per ton in 2023. Various factors, including inflation, operational challenges and new hire onboarding and training impacted our cost 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, most like the rest of the world, we experienced and are experiencing increasing cost to produce. Our average gold cost increased from $33.16 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 the 1 gigawatt Merom Generation Station. The transformational impact of acquiring Merom 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, Merom 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 markets.
Starting in 2024, we anticipate shipping up to 3 million tons of coal annually from our mines directly to Merom. The close proximity of the mines to the plant is about 20 miles, enables real-time adjustments that should promote additional efficiencies for both business segments. Moreover, at Merom, 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 Merom to cover a significant portion of the annualized fixed cost of the plant. While the capacity market will fluctuate over time, we believe that at current capacity prices, Merom provides a low-cost option to access 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 Merom and into the open coal market. In other situations, it may make sense to increase our shipments to Merom and sell additional energy in the wholesale energy market. In either case, flexibility is a key benefit that Hallador did not have prior to the acquisition.
We also recognize the challenges of operating the 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 downside risk.
Additionally, for us to operate Merom 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 decline in 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 at the end of fiscal 2022 to $85.2 million.
As of December 31, 2022, our liquidity stood at $32.1 million, and our leverage ratio had dramatically improved to 2.05x. Subsequent to year-end, on March 13, 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 12, 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 ask him to walk everyone through the purchase accounting associated with the Merom acquisition.
Thanks, Brent. Although the only consideration Hallador 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 tile. 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 21, 2022. The energy markets were volatile during this period. Thus, in the time between signing and closing the PPA -- in 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, 75% of this will be by May 31.
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 noncash adjustments.
I will now turn the call back over to Brent for closing comments.
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.
[Operator Instructions] Our first question today comes from Lucas Pipes from B. Riley Securities. Your line is open.
Thank you very much, operator. Good afternoon, everyone. Brent, my first question is in regards to liquidity. When you think about kind of the amount of liquidity the business needs on an ongoing basis. So 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? I would appreciate your perspective on that.
Yes. Thank you, Lucas. I think our goal is you can never have too much liquidity. Our game 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 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 12 months, roughly from today.
And I think that with contracts in hand that we have and then 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 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.
That's very helpful. And sorry, if I didn't catch everything there. You said that in 2023, it will be much of a contribution from the power plant. Did I hear that right? Or could you expand on that?
Yes. So if you look at the majority of our business, so 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 Merom and so -- and convert that coal into electrons. We think that judging by the forward power curves today, big 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've tried to outline is that the capacity markets today are robust and should materially cover most, if not all, the fixed cost 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 Merom 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 closed on the plant yet. So there was some -- we were not a 100 percent certain we could close on the plant. There's always challenges to that. So it was the -- 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 change and will sell less outside and more to ourselves.
What is the forward price for power for this market for 2024 today?
Yes, that's a proprietary number. So, we're not disclosing that.
That's helpful. And just because I tried to look through the 10-K and apologies, if it wasn't immediately obvious to me, but the contribution of Merom to EBITDA in the fourth quarter, where did that come in?
It was roughly 5 million later. Larry was the exact number?
It was like $5.5 million for Merom, for the 2022. So, we had like $56.2 million adjusted EBITDA Lucas, and about $5.5 of that was from the power plant.
And then is it possible, thank you very much for this. I'll do one last one I 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 Merom?
Well, again, I think our goal is to take as much coal as possible to merit because we think that converting fuel into electrons is a value-add, right? It should be 9x out of 10 our best market. There were some unique things that happened last year that last year market may have been one out of the 10 for a small window of time. So we chose to take advantage of that.
But I think 9x we'll try to take up to 3 million tons of our 7 million tons of production to Merom. And like I said, forward curves are certainly in support 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. And the balance, we are currently in a position to sell in the day-ahead market. So we're still looking at...
Let me add there. So Lucas, in your question on that table, the 7.5 and the 7.3 and beyond, there's zero to Merom sales in there. That is all third-party sales to third parties.
Our next question comes from Kevin Tracey from Oberon Asset Management. Your line is open.
Great. The first one is on the price coal tons, I guess, beyond 2023. In past 10-Ks, you disclosed the price position for the next two years in this latest 10-K, you haven't put out the price for 2024. But there's a footnote in your 10-K where you note that the performance obligation related to price tons is $593 million. So, if I use some quick math, 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 received from third parties next year to take a step down?
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 level we have is if we take 40% of our coal production to the Merom 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 and there's some reasons for that, right? There's -- 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 was storm Yuri, you saw several power producers who had sold, say, $50 per megawatt power were hit by that storm and couldn't produce and we're forced to cover at $9,000 a megawatt hour in the Texas market, and we're bankrupted pretty quickly.
Now we're in the MISO market, Texas is in ERCOT, the max limited is legal limit is $3,500 a megawatt hour, which means if you were caught in that event, you would go bankrupt slower. But those -- so we're working on the ways that we can lock in the profit potential for some of the plant 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 -- one of the trends that's going on in the industry is generation that has an on switch. And I would argue on-site fuel, coal, nuclear, is being prematurely replaced with generation that either doesn't have an on switch. Wind and solar or doesn't have on-site 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 to 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 '16, 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 it's these -- these super high price events are happening with greater frequency.
Though 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 ramped up and ready to go during these Maxgen events where we're seeing 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, gosh, if we are less sold on the power side, we think our earnings could be really lumpy, right?
Yes. So that's what we're trying about. So I hope that answers your question.
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? Or I think the 12 months that starts June 1.
So, the auction...
I'm talking related to the 68% of capacity that you don't need to sell who are you able to fully I guess, bid that into the auction that's happening shortly.
Well, first of all, let's not confused 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, by so went to a seasonal construct.
So our plants accredited capacity has various accreditations for winter, spring, summer, fall. And we sell -- 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 28. And the results of that will be announced a week or so thereafter. 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 and something -- 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 the Clair Moeller of MISO, who is the President and Chief Operating Officer of MISO, his comment is in regards to the last two winter events, extreme events is gas is now zero for two, right? And so we've seen PJM come out and their market monitors say, hey, we don't think we are recommending the gas plants that don't have now two transmission lines, should not be -- unless they have two transmission lines, it shouldn't be accredited 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 for my knowledge, it's not typically sold in the MISO auction, the MISO auction is the capacity auction. The energy side, 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 a PPA with like we do with the seller of the plant where we say, look, you're going to buy your electronic turbine. So, we're going to sell our electronics to MISO, but we're going to true up with each other adding…
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 -- what is the price in the PPA for Hoosier? And is that price fixed through 2025?
Yes, we're not disclosing that price. And we have confidentialities in those agreements where we cannot at this time. 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, 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 22.
So in the meantime, we had an invasion of Ukraine, which said kind of trigger -- 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 -- I'm saying that wrong, Pakistan, Pakistan, they had relied heavily on natural gas plants that import LNG. Europe did 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 was created a summer 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 we had a stat last night saying that 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 the BTU in Russia has declined significantly.
And I think you'll see production come off there probably permanently as U.S. energy companies and Western energy companies leave that country, that's got to be replaced. And those markets will turn back to the U. S. So, I think there's a temporary downturn here in those markets. To be fair on the coal markets people ask, 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 and big volumes. So it definitely -- we've improved the liquidity of the revenue stream of our company by having the Merom 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 going to see our balance sheet very much delever over the next 12 months. We already went from at 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 and replaced -- which was lousy, and we replaced that with our first quarter of 2023.
We expect that to further significantly deleverage our balance sheet and as we continue to pay down debt. So that's one of the ways to play defense is to have very little debt on our balance sheet, and that's a position that we're trying to get ourselves in.
Okay. And the last question, can you give us a sense of what the capacity factor of Merom was in the fourth quarter during the period which you own the plant and what you expect there going forward?
So we had some scheduled outage in the fourth quarter. So I don't know that, that would be a very leading statistic. And this year, again, what months are we talking about. Right now, both units are running at Merom. 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.
Yes. Thank you very much.
Yes, thank you.
Our next question comes from John Moore, a Private Investor. Your line is open.
Great. And this is a remarkable acquisition you made here of the Merom Power plant. And I guess my question is, are you there are a number of power plants in Indiana, they're going to be shut down. Are you considering acquisitions of more power plants?
Yes, I think we would always take -- we would always consider additional power plants. So 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 there will be more opportunities to look at similar transactions to the Merom transaction, but I can't tell you when and I can't tell you where 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 I had understood that it was sort of a May of '23 was going to be an important drop down in the percentage of the power that you agreed to sell to [Dufour]. I thought I had read a disclosure here that you had agreed to sell 70% of the capacity in up to 2025. Did I misread that? I haven't been able to reconcile these numbers.
You misread that. So we have 100% of the energy sold of the plant through May of '23 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 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 million of environmental expense we will have to invest that money if we want to 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 are -- that exist today, what 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 is one of the things that we're disclosing.
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?
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.
Our next question comes from Mike Rybak from Butler Hall. Your line is open.
So I guess my question, yes, I just wanted to dig in a little more on the power plant. So, you guys did $5 million of EBITDA in the quarter. What was the free cash flow associated with that? And then, I guess, taking a step further, if that's sort of a good run rate for '23, right, to take five, multiply it by four, that's $20 million. I mean if you're doing like $35 million of CapEx, it looks like it's going to be free cash flow negative to the tune of $15 million to $20 million in '23?
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 and scheduled outages in that quarter, so it didn't generate the entire quarter. We're telling you that we've got significant -- 100% 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 plan for both maintenance CapEx and realize the seller had announced in January of 2020 that they were going to close the plant. And so there's some catch-up maintenance that has to be done with that plan. I think on a going-forward basis, once we -- our maintenance is caught up, we anticipate the maintenance CapEx being somewhere in the $18 million a year range.
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 we kind of view it as, yes, 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 plan.
Okay. That's helpful. So if we think about sort of, I guess, normalized, I mean, I think you talked about '24 being a contribution year. I don't have the future curve in front of me. But as it stands today, and obviously, it's subject to change can 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, how do we think about sort of that normalized free cash flow generation of the plant today -- or the plant to 2024 based on the forward curve today?
Yes. 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 you 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? It's a cash flow 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, if gas is this price and a gas plant can produce an electronic at this price and that's where the power market should be. What the problem is these extreme events, no one wants to be caught short in the extreme events. So we're seeing -- but 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 the United States is looking to retire half of its coal fleet within the next 10 years, we think that's a lot of generators that have on-site fuel that 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 on-site 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 and the storm events is not good.
So we think that makes the value of our assets 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 saying, ALL right, we're going to 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 going to sell more in the spot market, our 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 paid legal limit.
I mean real-time market in MISO on December 23, at $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 we 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.
Okay. If I can just ask that question in a different way, I mean, obviously, at $58, which is where you contracted for 2023, that's a very healthy margin for you guys and you're probably incentivized to not sell into the plant. What is that what is that sort of price of indifference, right? Like is it a $50 at $45, you might see actually more of your volumes go into the plant rather than the coal wholesale market? I don't know maybe you can give a range, but I'd love to just understand kind of that point of the difference.
Well, it changes the forward power curves will tell you, hey, look, we see people out here willing to contract for a megawatt hour in July that might be a very different price than what they would do in 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 market.
So for example, we had announced in February that of 2022 that we would acquire the Merom generator. And we felt we had a very high probability of closing on that transaction, even though it was subject to various government approvals, right, FERC being the slowest our longest lead time of those approvals.
So during that period of time, we saw the coal markets, we saw multiple customers willing to pay an average price of $125, that was an average price. They were different prices in that range or 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 Merom Power Plant in 2023. I can't -- there's no set number, right? It was just look at both markets in that snapshot at 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 one out of 10 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 is 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 last -- earlier this week, that could escalate things. What would that do to energy markets. We're seeing saber rattling to some degree between the United States and China.
I personally, as a U.S. citizen, I hope that cools down, but those are the type of 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 energy markets. I don't think that will happen the majority of the time, but we just saw that 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 -- the energy crisis that went on to Europe last summer, the Ukraine invasion revealed that, it was there all along. We saw 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 -- because that response isn't there like it's been in the past.
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 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 in the dispatch curve as gas prices get low, coal, gas dispatch in front of coal.
If you have less gas coal generators over time, when gas prices get high, you're not going to see switching to coal generation because there is no coal generation, right? So to me, 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 -- 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 powered and fueled by something, all adds a lot -- the trade is moving our way.
Our next question comes from [Kevin Pounds] from Castleberry. Your line is open.
Yes. You're entering a new business. You retained the staff from the power plant or hired 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 to close, but are you going to have competition on pricing? Or you referenced this organization, MISO, I guess, that they make a deal with a group of utilities, is that correct?
So, MISO is the Midwest Independent System Operator. That's the reason it's 15 states and one Canadian province. Our power generators in the Zone 6 of MISO located in Indiana -- I'm sorry. I answered the last part of your question. What was the first part of your question?
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?
Yes. So, we retain 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.
But the plant manager of Merom is still there. He's done a great job, and the staff of Merom is doing a terrific job. We just wanted to make sure that we had CAMs as they are experts that run over 30 gigawatts of generation in the United States, 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 CAMs.
Great. And then on the coal side, other smaller cooperators have had significant problems with transportation and you're looking to increase production. Do you feel good about the how you're working with the railroads, et cetera?
Yes. I think there was a shortage of transportation in 2022. I think that is being alleviated here in 2023, so less was concerned about transportation today as we were six, nine months ago.
We have a follow-up question from Lucas Pipes at B. Riley Securities. Your line is open.
This is actually Nick asking a follow-up here. I believe the question was asked earlier related to the price Hoosier is paying through 2025. And I'm just seeing in the 10-K here, so I want to clarify that I'm reading that Hallador shale sell and Hoosier shale 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.
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've sold 20% of the power if available, but the minimum we have to do per year, I believe, is 70% of that 20%, if that makes sense.
That's clear, Larry. Thank you for clarifying that. 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 -- and maybe the cadence of costs throughout the year?
Yes. I think we've seen our productivity numbers for Q1 improve. And I think we'll see commodity price as things steel limestone and other things like that, diesel. Some of that pricing has come down in the market, but it hasn't. Our suppliers have contracts, too, right? So we don't -- 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.
Last year was kind of a crazy time where we saw dramatic 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? A high-margin business and so it got very difficult to get supplies, things like roof bolts that you run out of roof bolts or you run out of glue for the roof bolts 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 taking its foot off the gas a little bit as coal inventories have increased, which has just 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.
Got it. Well, that's good to hear. Brent. Appreciate all the color and continued best of luck.
Thank you, Nick, and I won't through too much at Lucas for having you asked 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.
This concludes our Q&A. I'll now hand back to Brent Bilsland, CEO, for any closing remarks.
I want to thank everybody for their continued interest in Hallador 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 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.
Ladies and gentlemen, today's call has now concluded. We'd like to thank you for your participation. You may now disconnect your lines.