Hallador Energy Co (HNRG) 2022 Q3 法說會逐字稿

Good afternoon, and thank you for attending today's Hallador Energy Third Quarter 2020 Earnings Call. My name is Jason, and I will be the moderator for today's call. All lines will be muted during the presentation portion of the call an opportunity for questions and answers at the end. I would now like to pass the conference over to our host, Rebecca Palumbo, Investor Relations.

Thank you, Jason, and thank you, everybody, for taking the time to join us today. Yesterday afternoon, we released our third quarter 2022 financial and operating results on Form 10-Q that is now posted on our website. With me today on this call is Brent Bilsland, our President and CEO; and Larry Martin, our CFO. After the prepared remarks, we will open the call up to your questions. Before we begin, please note that the discussion today may contain 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 underlying assumptions prove incorrect, actual results may vary materially from those we projected or expected.

For example, our estimates of binding 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 may be required by law. For a discussion of some of those risks and uncertainties that may affect our future results, you should see 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 and 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 number is (844) 200 6205 access code 840309. And with that, I turn the call over to Larry.

Thank you, Becky, and good afternoon, everyone. I will start with our review of operating results and before I do, I would like to define adjusted EBITDA as operating cash flow plus current income tax expense less the effects of certain subsidiary and equity method investment activity plus bank interest, less the effects of working capital period changes, plus cash paid on asset retirement obligation reclamation plus other amortization. For the third quarter, Hallador made net income of $1.6 million or $0.05 a share. We have lost $11.9 million net income or $0.38 a share for the year. Our adjusted EBITDA for the quarter was $18.4 million, $32.5 million year-to-date. Our bank debt was decreased by $17 million for the third quarter. We had a positive borrowing of a net $2 million for the year. Our bank debt at the end of September was $113.7 million. Our net debt reduced by our cash was $106.7 million, and our debt to EBITDA for the 3 quarters is -- or for the prior 4 quarters is 3.5x well within our covenant of 4.5. I will now turn the call over to Brent Bilsland for our review of the quarter and beyond.

Thank you, Larry, and thank you, everyone, for joining us today. During Q3 was transitional and a very positive quarter for Hallador. During the quarter, we signed the contracts for 2.2 million tons of new coal sales at an average price of roughly $125 a ton of which a small percentage of deliveries began during Q3 and will continue through the year-end 2025, with the majority of these tons to be delivered starting in the fourth quarter of this year and throughout 2023. These contracts put us in a position to generate up to $160 million of EBITDA in 2023 and will be a significant driver of our efforts to move towards the position of being net debt free next year. During the quarter, we shipped 1.7 million tons at an average sales price of $49.01. This represents a price improvement of $8.78 a ton over the prior quarter. We expect Q4 pricing to be similar and look for our average price to continue to improve through 2023 to a price of around $58 per ton.

To meet these new orders, we have been expanding our coal production by hiring additional employees and putting more units to work at our Oaktown mining complex also opening a small surface pit near Freelandville, Indiana and moving our [Athen] whole production to a small surface mine pit near Petersburg, Indiana at our former Prosperity Mine. This has required us to increase our CapEx spending, which is up roughly $20 million year-over-year. And we have been successful in increasing our headcount 24% year-over-year. Thus, we have incurred greater employee acquisition and training costs, Freelandville and prosperity production began during the third quarter. Volumes from these new pits are expected to be higher cost and are forecast to represent approximately 8% of our 2023 production. In Q3, Hallador's operating costs increased to $37.46 per ton.

Our [neuro] workforce and Surfers pits will ramp up to reach peak productivity and with expectation of only slight easing of inflation in 2023, we expect our mining costs to remain elevated in 2022, followed by potentially a small cost reduction in 2023. We believe that the increased market prices for coal is clearly justified, taking on these increased costs and investments. To help fund our increased CapEx and improve our liquidity, we sold $29 million of convertible notes, $10 million of which were sold in Q2 and $19 million of which was sold in Q3. The $10 million of notes issued in Q2 have been converted to Hallador stock, bringing our current share count to 33 million shares. If all notes are converted to stock, this would equate to increasing our share count from 30.8 million shares at the beginning of Q2 to 36.1 million shares at some time in the future prior to year-end 2026, representing an approximate 17% increase in share count. Bank debt was reduced during the quarter by $17 million, bringing the balance owed at the end of Q3 to $113.7 million.

Subsequent to the end of Q3, on October 21, we closed the acquisition of the 1 gigawatt Merom Generation Station from Hoozier Energy. At closing, we received net payments of $34 million. These funds were part of capacity payments owed to Hallador through our power purchase agreement with Hoosier. With these funds, we paid down an additional $27 million of bank debt. Thus, when including the $17 million of bank debt paid in Q3, total debt was reduced by $44 million or 34% of the third quarter's beginning outstanding balance, bringing our total bank debt on October 22 to $87 million and further increasing our liquidity. This combination of debt reduction and rising EBITDA is quickly leveraging our balance sheet, which we anticipate being less than 2.5x debt-to-EBITDA by the end of the fourth quarter and expect to be approaching a ratio of less than 1x by the end of the first quarter of next year.

Our goal at Hallador is to deleverage our balance sheet and to create multiple uncorrelated revenue streams that take advantage of our unique place in this energy market. The acquisition of Merom is a significant step forward in this pursuit as it provides us the ability to monetize our coal production through both capacity and energy sales, while also providing us a platform for potential future investments, including new generation and energy storage. As capacity payments are currently covering most of the fixed cost of the plant, Merom provides optionality to Hallador in both the coal markets and the energy markets.

Starting in 2024, our Sunrise Coal subsidiary has the flexibility to sell up to 3 million tons, which represents 43% of our coal production annually to Merom, if the economics and energy sales dictate or divert some portion of set tons to third parties if the economics of outside coal sales creates a higher value. In 2024, Hallador anticipates 4 million tons of annual coal sales to outside parties, while maintaining the flexibility to utilize its remaining coal production to generate up to 6.5 million megawatt hours of annual energy sales at Merom. We believe that this flexibility gives Hallador a tremendous opportunity to take advantage of the most favorable economic conditions in each market. With that, I'm going to open up the line to questions from the audience.

We will pause briefly as questions are registered. Our first question comes from Lucas Pipes with Ridley Securities.

on behalf of

This is actually Nick asking a question on behalf of Lucas. Once you hit the net debt target in 2023, how would you describe your capital allocation objectives? Do you think M&A could play a role? Or are capital returns more likely in that case. Thank you so much.

Well, like I said, I think we've got the contract in place to be net debt-free or we at least forecast, we think we can hit that target in 2023. But certainly, we're deleveraging extremely quickly which is great. This is where we want to be, and that's kind of who we are. So I don't know that we're in any hurry to make any decisions as to what to do with excess capital. We probably wouldn't do anything until 2024. I think you'll see us look to what are the opportunities to use our capital to make forward energy sales and be able to lock in margins and position the company from that perspective. I think that's some of the things that we're looking at today. But all things are on the table. We're not currently in any M&A discussions, but the right opportunity came along, I guess, we would consider it. But for now, our primary goal as stated, is to deleverage the balance sheet and focus on creating ways to get what I call uncorrelated revenue streams.

So what I say that is for a long time, our revenue stream has been selling coal with Merom, we have the ability to sell capacity, sell energy potentially use the landfill there to create -- take gas from other utilities and create revenue there. We've got some permanent work to do that. But we see other opportunities around that facility at some point in time, that some of -- do we repower that site with solar and battery. I think that saying right now, the market is saying it needs the capacity so we plan to invest in that plant and have it serve the market for quite some time. So but those are our thoughts today, Dave.

Got it. Got it. No, that's very helpful. Maybe just on Merom, what kind of breakeven price should we think about on a dollar per megawatt hour basis as far as those tons that you plan to dedicate to Merom today.

That's just not a number that we've released to the public yet. So I would say this, that because we have that cost coal production that we can put to that plant, we feel that plant has the lowest base cost of any coal-fired power plant in MISO. So, we think it's definitely positioned in very good shape to be in a position to run if that's the best use of our fuel.

Got it. Got it. Okay. That's helpful. That's all for me for now. I'll jump back in the queue, but thanks for the color.

Our next question comes from Kevin Tracey with Oberon A.M.

Great. So Brett, in the 10-Q, there was a note you acquired $17 million of coal inventory with the Merom acquisition. I understand who your original plans were to shut the plant next May. So am I right in thinking coal supply beyond May will be tough. And given spot prices are in the triple digits. -- that Merom probably won't operate much in the second half of next year?

Yes, I think that -- so I think your question was, do we have a lot of fuel post May of '23? The answer for that is no. S[\o we do not expect that plant to operate much from, say, June to December of '23 with current fuel procurement. That could change but that's the position we're in today.

Okay. And then a related question to that is I think the next capacity auctions coming up in April for the year starting June of 2023. So just given the -- I guess what you just said kind of the lack of coal supply, at least for the second half of '23. Does that going to prohibit Merom to enter into that capacity auction for the -- well, what I think it's 68% of the capacity that you're not selling to Hoosier under the PPA? Or is there a way where you can partially participate for the months in 2024 when Oaktown can insure coal supply?

Yes, twofold. One, we do believe we have enough whole procured to meet our requirements. We also are working on, as I said earlier in the call, increasing our coal production. So that's another way we can put more fuel to the plant. We can acquire fuel from other third parties. And those are all things that are on the table, but we think we can fully participate in the capacity auctions and markets in future years, '23 and '24 and beyond.

Okay. Great. And just to confirm this kind of $39 million of advanced and passive payments from Hoosier, there's no cost or cash cost associated with that is there? And then you have the PPA for 100% of capacity through next May, but then 32% of capacity through 2025. I guess should we expect under that PPA for Hoosier to pay additional capacity payments in future years?

Yes, they do pay future capacity payments in future years. Some of those payments are in 2023. They are reduced because they're buying less capacity. But I think we come back and say, we still got capacity to sell. We have a lot of interest from other parties and capacity pricing to date is very good. So there's more retirement of generation in MISO that have an on switch and they're being replaced in large part by generation that does not have an on switch. So, capacity continues to tighten. It is our viewpoint and belief that capacity becomes more valuable over time, not less valuable over time. We think that those are comments that are also being exited by MISO directly. If you read what they're saying, I think they realized they've got a capacity shortfall in future years, and they are trying to modify their auction process to incentivize the market, to stop a slowdown retirements and speed up additions of capacity.

So we think, from our perspective, that gives -- that puts us in a position where in most years, a significant portion of capacity are a significant portion of our fixed cost of the plant can be covered by capacity payments. And if that holds true, then from our perspective, we kind of get a free option to put fuel to the plant or fuel to the public. Now you're right. I mean, we can't put 0 fuel to the plant, but we can vary that amount. If third-party market is willing to pay a significant premium above what we think the power markets will bring. And as evidence of that, that's what we did basically in the -- we agreed to those contracts in Q2. We signed those contracts in Q3 to sell it to the market versus take it to the plant. -- we felt that, that was the best risk-adjusted return at that time that was available to us. And realize at that time, we weren't 100% sure we were going to close on the plant. We were 98% sure. So we were glad to finally complete that transaction.

We're thrilled to have Merom on our portfolio. We think it dramatically changes our company, and we think it puts us in a very unique position to be a part of this transition. Today, the plant is very much needed in the grid from a capacity viewpoint. In the future, it gives us a great platform for investment and how our shareholder investment in new generation stores, which if I was sitting here today, I would tell you, it'd be sold in a battery, time will tell.

Yes. Okay. Just to clarify, on that $39 million capacity payment in future capacity payments, there's no kind of pass costs associated with that revenue. You just what you're standing by with the capacity willing to provide. Is that right?

Yes. So what that really obligates us to do with MISO at a 30,000-foot level is by selling that capacity, we are obligated to bid that plant into the day ahead market each and every day. Now we have some flexibility as to what price that plant gets bid in at. There are rules around that, and there's a market monitor that evaluates that to make sure that we are complying with those rules. But by selling your capacity, you basically are saying, "Hey, look, I've got an asset that's ready to go. I've got the employee staff to make it operate and I've got fuel procured and in position with my inventory in existing contracts to be able to meet the capacity factor that we think that plant will run at. And we are in a position to say, yes, all those things in 2023 and beyond. So ..

So even though we don't correlated expenses related to that capacity income, we do have fixed costs at the plant in order to bid that capacity into the -- into whoever is buying it or the market.

Got it. Got it. Okay. If I could just sneak one last one in, just on the CapEx going forward. I understand it's elevated this year as you're opening up these new sites. But in the past, coal CapEx kind of spend more in the $30 million to $35 million range. I guess I'm just curious, next year, what are you thinking? Then if you have any comment on what Merom's kind of normalized CapEx will be that, that will add as a company, that would be great.

So yes, we expect our coal CapEx going forward to be a $35 million to $40 million range. It could be a little higher next year even with the surface equipment ramping up the 2 surface mines we have. Then our CapEx at Merom, we have 2 categories of CapEx there. We have just regular reliability, maintenance CapEx that will be in the $15 million to $20 million range. Then we have to start analyzing our ELG to get into the affluent limitation guidelines with that plant by 25 and when we will start that process. It's about $40 million to $45 million over the next 3 years, and we haven't figured out our timing yet. Right now, I think we expect maybe $17 million, $18 million next year, but we haven't got into the planning and the POs for that since we just bought the plant in October.

Once again, if you'd like to ask a question, -- our next question comes from Ted Waters, a Private Investor.

The question I had was could you tell me a little bit about your ability to sell megawatt hours into the future? For instance, could you start locking in 24 megawatt hour pricing going forward in the near term? And if so, what would that be equivalent to in terms of coal tons? For instance, you sold $125 tons in Q3. If you were to sell into the megawatt hours in '24 today, what pricing is that put in today?

Yes. So the answer to the question is yes. We do have the ability to sell either in the day-ahead market or we can sell basically in a bilateral agreement with an energy trading company or a utility that would like to buy megawatt hours. What is the price of that? That's up for negotiation. That changes every day, and every hour within the day. We do have curves that kind of show, where it thinks the power market is going forward. It's I don't know if I'm ready to release any of that from a proprietary perspective. As far as at the plant, basically 1 ton of Oaktown coal at the Meom plant generates about 2.2 megawatt hours. So, if you take -- there's various curves out there and various assumptions. But if you take a megawatt hour, the variable costs on that, you're going to have about $5 a megawatt hour of variable cost.

So let's just talk for easy math. The megawatt hour was $50. It's the equivalent of 1 ton of coal is going to produce 2.2 megawatt hours, so that's $110 per ton equivalent track $5 of variable excuse me, I've doubled it there. So $10 now. So now you're roughly at $100 coal then once your fixed cost at plan, it's a capacity payment covering your fixed cost to the plant? Or is it short? Or is it long? Is capacity paying exceeding fixed cost of the plant. So that's kind of how we look at it. I hope that made sense.

Yes. I assume now that's how the math you do, when you decide to sell to a third party or do the megawatt hours, that's interesting.

That's basically exactly what we're doing. We're looking at what our assumptions are on forward power prices, realizing those change every day and what can we find a third party that would be willing to transact, say, in 2024 for those megawatt hours. There's some requirements with that. I mean there can be letters of credit that are required from the counterparty to kind of secure and guarantee delivery of those [electrons]. So those are all things that we have to kind of look at and keep it balanced. But look, there's been a lot of disruption in the energy markets with what's going on in Europe, so you've got a lot of coal and natural gas or LNG flowing to Europe. So domestic coal is competing with that. And if you look at it right now, gas is cheaper than coal, but the market needs all the coal generators to run.

So you've kind of got coal generators in our opinion, setting the price of power. So that will happen as long as demand exceeds all the gas generation and gas prices stay or [direct] . There's a lot of dynamic here. There's a lot of prices that move each and every day. But right now, there's very healthy margins in producing power, and there's very healthy margins in selling coal in the open market. So we're happy with the position that we're in as far as getting the company net debt free and contracting for capacity and energy prices that we think we can make a profit at. So that's where we're at.

Our next question comes from Arthur Calavritinos with ANC Capital.

All right. Let me ask you something on the debt reduction to 0. That's going to happen -- you've got that locked in for this year, right?

I'm not quite sure what you mean by locked in.

It's going to be paid off. I mean 95% confidence interval. You know what I mean? I mean given what you're looking at right now, we're not going to get any surprises and say, okay, we couldn't take it down like at all. I mean, right now, you're pretty confident the debt should get to be diminished, by year-end?

Yes, I think from our perspective, we've contracted to the coal, so we know that our average sale price is going to come up significantly. So we're going to see significantly higher margins, something in the low 20s. We have to produce the goal, which we've always historically been able to do. We're trying to -- we are increasing our production. With those increases in production, we have a slight increase in cost, but some of that is coming from higher cost surface pits. But we're forecasting a higher cost curve moving forward. And we're relying upon our customers providing transportation to pick up the coal, which that piece is out of our control. It's in our customer control. But from a forecast perspective, we see no reason why we shouldn't be materially net debt free by the end of the year. [indiscernible]

23. Yes, yes. So again, now, a different question. When you guys are looking at projects, right, internal rates of return with the businesses, any-- I don't kno2q... Discipline? Or does -- are you seeing better opportunities? You mentioned storage. Again, it must be difficult to do a spreadsheet to model that out. Because what I'm concerned about is I don't want to see you guys do like a lot of storage or something and it doesn't work out. That's all. So I'm just trying to figure out what your discipline is how you look at stuff and how you decide to exit if that were to happen.

Yes, I think our focus right now is that we are essentially long energy long capacity. And we're in a pretty good sales position. If you look at us for the next couple of years, our hedge position there is pretty well hedged. We don't have a lot of excess electricity to sell until 2024. So we're trying to figure out what's the best way to do that. And there's various ways to do that, some of which require some amount of capital. And so what we're saying is, look, 23 is about getting our balance sheet in a very delevered position and trying to position the company to have profitable power capacity in fuel sales in 2024. So that's kind of what we're focused on. When we talk about energy storage, the Inflation Reduction Act was released and approved this year. However, there's still writing some of the technical rules around that.

And so I don't think it's fair for us to say today we will or we won't do battery storage because, quite frankly, we're waiting for the rules to be finalized to understand is that a good rate of return for us or not? Today, I couldn't tell you yes or no. So for those rules, we'll evaluate that. I think what we're trying to point out to everybody is to some people, this acquisition appears as if a coal company bought a coal-fired power plant. What we're trying to say is that's true today, but in the future, this really is a transition platform? I mean what solar developers and battery developers are dying for is a place to plug into the grid. The MISO 2 study has been backed up 4 years. PJM study so far backed up, they've stopped accepting applications. We don't have to do a few study. We already own the interconnect. We already have rights to that interconnect today.

So if our management team and Board decides that the best use is to close our power plant at some point in the future and repower that with solar and battery. We have very minimal work that we would have to do with MISO to get approval to do that versus the developer down the street who's trying to jump on the grid somewhere, I mean they've got to apply in PJM, they wouldn't even accept the application in MISO, they'll accept the application, but they might be 4 years. If your application happens to be on the edge of MISO grid near another ISO, both ISOs have to approve that application. So that's -- I mean one of the things that is causing a problem with this transition from fossil to renewables is there's not enough places to plug in. 

And we're turning off generation as an on-switch we're turning off generation that can run hours in a given year, and we're replacing it with generation that cannot be turned on from the great operators per standpoint, and it's only got around 20 hours, 20% of the hours in a given year. And so that's the challenge is that the grid is [seeing] today. I spent some time last week with a couple of different grid operators who basically outlined, hey, look, we -- the number of levers we have to totally keep the system balanced is being reduced. Which then leaves in as demand response is the new lever they're looking to reach for, well, demand response is we're shutting power off to someone. That's what demand response is, who is getting their power shut off. And hopefully, they have agreed to add ahead of time. That's not always the gate.

So for all those reasons, the value of a plant, such as Merom that has been well invested in, it has all this environmental compliance investment in place, except for ELGs, we will have to invest in ELG to run beyond 2025. And we look to make those investments in that '23, '24, '25 period to be in a position to do that. As our thinking today, we've not pulled the trigger on that yet, but that's what we're evaluating in real time. But we think this asset becomes more valuable because of the attributes it can provide to the grid because there are fewer and fewer generators that have these attributes that are available to the grid. The motivation of a public utility is very different than a wholesale power generator, which is what how it will power our subsidiary, how we're powering [that owns Merom] essentially what it is. So for those reasons, that's what we look like, and this is what our thinking is.

Got it. And one last thing, we like I was going to say we're in Boston says we're going to have like some -- we've already had shutdowns in the summertime, the industries nobody cares about. But if we get some shutdowns, national use type of stuff like in New England, right, where it's really tight. I'm just thinking how you -- like where you guys are or let me specifically asked, would legislation or regulation change to be more favorable to you as people realize or finally, the regulators realize and the citizens are valuable these things are? We're going to...

Well, yes... I think anyone who sits in the dark for any period of time realizes how valuable electricity is. They say power generation is 7% of the U.S. GDP, but it's the first 7% because without it, nothing else works. So we've seen this happen. Look, every grid that approaches 30% renewables crashes. We've seen multiple crashes in Casio. We've seen it in Texas. Energy Capital in the United States, we've seen a 5-day outage that we cost over $200 billion than 100 people lost for life. And we saw Texas make massive changes to the rules around power generation and ELCOT, the Electric Liability Council of Texas. So I hope this doesn't happen in other ISOs throughout the country, but I wouldn't bet against it. You've got literally the grid operator of MISO is saying, our plan is to be backed up by PJM plan is to be backed up by MISO. But if they're having a bad day, the same day, we're having a bad day, this nation is going to have a bad day.

I mean, that's a public quote from the Chief Operating Officer of MISO. So they realize that the grid is changing very rapidly, and this is bringing a new risk profile to the grid. It's being done in the pursuit of trying to reduce climate change, but there's new risks that are associated with that. So from an economic perspective, we think all this is happening too fast. We think the Merom plant needs to stick around for a while. We've said all along, we have the rights to shut it down when we want to convert it to something else. We're going to let the economic market decide. And right now, the signals they're telling us this plant should remain online, and we should continue to invest on it, and that's where we're headed today.

Okay. Great. Great commentary. Thank you very much.

Our next question comes from Andrew Love with Hallmark.

A little more clearly, what it means when you sell capacity? Are you selling something that then is a bilateral obligation to deliver electrical energy at a market price or at a predetermined price or what?

If you are a public utility and you have -- so you're a load following member of the grid, which means I have in that particular scenario, someone who has 500,000 customers, and they need to be able to buy electrons from MISO to sell to their customers, so MISO basically says, if you want to buy a gigawatt worth of power in any given hour, you have to supply MISO with a gigawatt of rated capacity. So there's all sorts of different ratings on power plants. MISO's nameplate -- excuse me, Merom's nameplate is 1,000 megawatts. We'll actually produce somewhere around 960 megawatts in any given hour. It's rated capacity with MISO today, which changes every year is 917 megawatts. So we can sell because we are not a load following member. We do not have customers that were selling electricity to. We don't have rate payers. We're a wholesale power generator.

So since we are not buying electrons from MISO -- we have no obligation to provide them capacity. We have capacity. So we sell our capacity to different utilities. In this case, we're selling part of it to Hoosier. We have one agreement with another utility in place today, where we're selling capacity so they can use that contractually to show to MISO that they've met their obligation to buy electrons from the grid. So if somebody wants to buy 100 megawatts worth of electricity for MISO in 2023 for the 2023 calendar year, which is June 1 of 23 through May 31, 24. They could come to us in there. However, we would like to buy 100 megawatts of capacity from you all. And here's the terms and conditions that we agreed to.

But when you sold that what does that ...

So what does that obligates Hallador to bid in its plant into MISO each and every day, which basically says, we send a message to MISO saying that for tomorrow, we're willing to bid in at these hours, this many megawatts at these prices.

But you must have an outlook... You must have an obligation to meet some price criteria. Otherwise, it doesn't mean anything.

Correct. So there are parameters about what price we can bid in. I think the limit is up to 3x our cost, where we can bid as low as we want. We can bid at a loss if we so choose.

And then if they accept it, you must deliver?

Correct and we get paid. So we -- let's say we bid it at $40. So let's say, for that given hour of the next day, the last generator to turn on for that hour bid in at $60, we would get paid the $60 price. So we're to turn on. All Baroi is doing is matching demand to supply. So think of it like a layered cake, where you've got the wind operators may be bidding in at $5 a megawatt. You've got the solar guys coming in and saying, "Look, we'll provide these hours at $6 a megawatt. You've got the nuclear plant saying, "Hey, we're either on or off, we're going to be on. So we're going to bid in at $10 a megawatt. And then now you have the assets such as gas and coal coming in higher up the stack and bidding in. What MISO was saying is, hey, look, we're going to bid this all the way up until we get enough left generation to meet load. But everybody gets paid the highest price for that particular hour.

And then a follow-up. All in all, what was your prediction of CapEx for 2023.

Yes, it was 35 to 40 on coal, and it was about 15 to 20 for reliability at the plant and then around 17.18% for ELG...

ELF means what?

The effluent limitation guidelines that the EPA put out a few years ago that has to be -- we have to be in compliance with by 2025. That’s roughly $40 million to $45 million over the next 3 years. And so...

Our next question comes from Jeff Bronchick with Cove Street Capital.

Note. So just quickly, out of the $150 million in EBITDA expected in 2023, is that all coal? Or does that include the capacity payments from Merom?

No, that includes the capacity payments from Merom. But most -- I mean, the majority of our EBITDA in 2023 coal because of the PPA we've entered into and the fuel limitations for the plant.

Got it. And when you say the capacity payments basically enable you to run Merom at break even and then you get all the optionality. Is that on an operating basis? Or is that on a cash flow basis, including that $15 million to $20 million maintenance and then the ELG payments?

So what we're saying -- I'm sorry, Jeff, what we're saying is the majority of our EBITDA is coming from our coal production in 2023. In 2023 from a plant perspective, we have a fixed cost of that plant, which is mostly labor. We get capacity revenue, which in 2023, we anticipate will mostly cover nearly all of the fixed costs of that plant -- we do not have -- we're going to run -- we've got a fair amount of power sold to Hoosier in January, February, March, April and May, but that's at a relatively low price. So we made the margin on it, but we don't make a huge margin on that. We are more unfold starting in June through December of '23. But we don't have a lot of fuel to put through the plant. So we don't expect -- even though we can make potentially more money on a per megawatt hour basis because we could sell electrons at a higher price.

We currently don't have a lot of fuel bought. We had some tool bought, nothing meet our requirements in 2023. So all we're trying to signal is that we don't today, we don't anticipate making a lot of money at the plant in 2023. We expect that to change in 2024 in that we have unsold coal at Oaktown that we can take the Merom, and we can sell that -- we can sell electrons out of Merom either on the day-ahead market or a bilateral sale to, say, a public utility or a trading company. And we think judging by where we forecast prices to be today that we can make a good margin on that in 2024. We've not put out any forecast for 2024 results. But [inaudible]

You still have to spend $15 million to $20 million, whether you run the plant or not, unless you truly close it down for good.

Correct. So what we're saying is, is that Hoosier was in the mode of we're going to shut this plant down. And so they, as you [do], did not spend as much money on maintenance of the plant here in the last 9 to 12 months. So what we're saying is we've got some maintenance elevated maintenance expense on that plan to kind of get it in a little better condition than it's in today or better condition, not a little better. And then we've got some money that we need to spend to become EOG compliant. As far as environmental control, this plant has almost everything you need to meet today's compliance requirements, but for it does not have an affluent limitation guideline control system.

So that's is an investment that we're evaluating today to make sure that we choose the right technology. The EPA is still tweaking the rules around this. So it makes it a little challenging to know what to order when they still haven't set the rules and then race to get in compliance by the end of 2025. So for the 2026 year. We wouldn't do that expense if we didn't plan to run the plant beyond 2025. So we feel we can make money at it. And quite frankly, we think this has put our company in a much better position in that our coal is not the most liquid market? I mean there's limited buyers. There's limited sellers. We tend to lock up for periods of time, but the window of opportunity to sell only open and closes so often. If we take our coal to our plant, we can sell electrons every day to day at market. So we have dramatically improved the liquidity of our revenue stream with the acquisition of the Merom plant. And we have dramatically improved

And so that sort of in a similar answers my next question. Really, I mean, it was either this plant was 100% closing or you were the only guy because you obviously -- it's a story of life of if you can sign 10-year contracts at $125 a tonne, one would do that. And conversely, your customers wanted you to sign 10-year terms at $32 at the bottom. So I guess that's really your answer that, look, we need to -- we should be balancing the world, and not every day is going to look like it does today. Ergo. We should be -- we'll sell 2 million tons at $125 million, but we're always looking for ways to derisk and take less for longer duration and mirror the it fits into that game plan. Is that -- am I getting that right?

Well, I think the plan gives us a lot of optionality, Jeff. I mean -- what I think is what you're saying is that the fuel market, our traditional market, that's still available to us. And if that's the best market, that's where we'll go. If that makes you a Hallador shareholder the most money on a risk-adjusted basis, then that's where we'll go. I didn't think that opportunity would exist personally. And yet it happened in the second quarter of this year. Now to be fair, I say risk-adjusted. We didn't have the plant in our control at that time, and it wasn't certain to us what would power prices be by the time we had the plant in control. So it was very easy to say, no, we're going to sell this on the open market. We're going to lock that in, that gives everyone great visibility as to what our economics look like going forward.

What we're saying today is, look, we're working right now to get more fuel or to find a way to get Merom to be more profitable in 2023 because we have the capacity to generate electrons. We need fuel. And we're working on some ideas. But keep in mind, we've owned this plant now for less than a month. And no one really -- you can talk about ideas with third parties prior to owning the plant, but it always comes back to, well, are you going to buy this thing? When is it going to happen? Those questions are behind us now. So now conversations with third parties are much more meaningful. And we're hopeful that we can transact in a capacity that adds to the EBITDA that we're projecting for 2023. So we think there's upside if we are successful in what we're trying to put together, time will tell. As far as in 2024, we -- at today's market prices, we know we can make money at the plant in 2024, significant. As we get closer to that and as we lock in more, we'll shed more insight into that. But for now, we know that it's given us a lot more liquidity because it's given us another avenue to sell and we can always sell in the day-ahead market. Now you're a price taker, but it's liquid.

Got it. Okay. And my last -- just the last thing to recall is that this is a bold scheme, thoughtful, interesting optionality, get it could work really well, could be a neutral, could be a complete time sucking mess, life is full of uncertainty. And my point being is that you guys say this, you guys adopted a new -- you got a grant of an RSU plan that is just time weighted. I would say, if I were you and I with the Board, I would have doubled or tripled the RSU package. But I would have made it committed to either some sort of a shareholder return or some sort of an operational thing that would greatly pay you and hence us if this plan is bold and fruitful. And it would docu if it's -- well, we gave it a world didn't work as opposed to just kind of waking up and getting 3-year time best in RSUs would be my mental comment, which you don't have to address, but I would just throw that in your lap.

Our executive teams are based on metrics based on both EBITDA and...

Yes, but the annual number exactly short term. Yes. I mean [inaudible] should be paid more. That's a winning argument for you. So you should just take it as is, and I appreciate your time

 Our next call comes from Lucas Pipes from B. Riley Securities.

Yes. Frank, you spoke about the converts in your prepared remarks. And just maybe as you think about potential future sources of capital, would you be open to more converts? Or might you look to other sources at that point.

Well, I think at this juncture, we are significantly deleveraging our balance sheet. And when we did the convert, it was at a time where our EBITDA performance was poor. And we had -- yet at the same point in time, we were knocking on the door of all this opportunity but to take advantage of the opportunity. And when I say opportunity, that is sell colo prices, increased production, acquire the Merom power plant. Those are kind of the 3 things that we're laying in front of us. So to take advantage of that, we knew we had to spend more money on CapEx. -- and we couldn't go really rely on any more of the debt market. So that's why we went to the convert. Looking forward, we're seeing the opposite. Our balance sheet is completely deleveraging. And so we feel that the debt capital markets should be sufficient to meet our needs. So I don't -- at this juncture look to do any more converts, and we just look to leverage our balance sheet and work on continues to create cash flow streams for the outer shareholder.

Got it. Very helpful. And then maybe just one more for me. You referenced rail performance earlier. And I believe last quarter, you referenced around 85% of scheduled deliveries were being shipped. Has this figure improved? And maybe just how are discussions progressing with these rail providers as you're kind of looking to return to higher levels.

Yes, it's kind of customer by customer. Some customers are doing really well, picking up what they're required to pick up and others are not. And we're in communications with both of those. And we have -- I would say, performance on that front has been more of the same.

Got it. Fair enough. Well continued best of luck.

There are no further questions. I'll pass the call back over to the management team for closing remarks.

Y Look, I appreciate everyone taking the time today, and we're very excited about the future of Hallador and the position that we're in. And we see as much opportunity in front of us, as I think we've ever seen in the history of our company. So we're excited about that. We think we've got the management team and getting the capital structure in place to take advantage of those opportunities. So look for more interesting things out of us, and we look forward to talking to you next quarter. Thank you.

That concludes the conference call. Thank you for your participation. You may now disconnect your lines.