Good afternoon, and thank you for attending today's Hallador Energy third quarter 2022 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 with an opportunity for questions and answers at the end. If you'd like to ask a question, please press star one on your telephone keypad. I'd now like to pass the conference over to our host, Rebecca Palumbo, Investor Relations.
Thank you, Jason. 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 financing 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 as 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 of the earnings call is also available on Hallador's website. We encourage you to ask questions during our Q&A.
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 844-206-205, access code 840309. 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. 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. Our debt to EBITDA for the prior four quarters is 3.5 x well within our covenant of 4.5x. 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. You know, 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 a 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 eighth and the 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. 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, Hallad or's operating costs increased to $37.46 per ton. Our newer workforce and surface pits will ramp up to reach peak productivity and with expectations 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 clearly justify 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 were 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 21st, we closed the acquisition of the 1 GW Merom Generating Station from Hoosier 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. That's 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 22nd to $87 million and further increasing our liquidity.
This combination of debt reduction and rising EBITDA is quickly deleveraging 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 investment, 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 of energy sales dictate or divert some portion of said 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 MWh 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 gonna open up the line to questions from the audience.
If you would like to ask a question, please press star followed by one on your telephone keypad. If for any reason you'd like to remove that question, please press star followed by two. Again, to ask a question, it's star one. We will pause here briefly as questions are registered. Our first question comes from Lucas Pipes with B. Riley Securities.
Yeah. Thank you, operator. This is actually Nick asking a question on behalf of Lucas. Once you hit the net debt target in 2023, you know, 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, you know, like I said, I think we've got the contracts in place to be net debt free, or we at least forecast we think we can hit that target in 2023. Certainly we're deleveraging extremely quickly, which is great. This is where we wanna be, and that's kind of who we are. 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 till 2024. I think you'll see us look to, you know, 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.
You know, all things are on the table. you know, we're not currently in any M&A discussions, but if 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, you know, focus on creating ways to get what I call uncorrelated revenue streams. when I say that is, you know, for a long time our revenue stream has been selling coal. With Merom, we have the ability to sell capacity, sell energy, you know, potentially use the landfill there to take ash from other utilities and create revenue there. We've got some permit work to do to do that. we see other opportunities around that facility.
Do we repower that site with solar and battery? You know, I think they're saying right now the market is saying it needs the capacity, so we plan to invest in that plant and, you know, have it serve the market for quite some time. Those are our thoughts today, Nick.
Got it. No, that's very helpful. Thanks, Brent. Maybe just on Merom, what kind of a break-even 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? Thank you so much.
You know, that's just not a number that we've released to the public yet. You know, I would say this, that because we have at-cost coal production that we can put to that plant, we feel that plant has, you know, the lowest dispatch cost of any coal-fired power plant in MISO. You know, we think it's definitely positioned in very good shape to be in position to run if that's the best use of our fuel.
Got it. Okay. That's helpful. That's all from me for now. I'll jump back in the queue, but thanks for the color.
Our next question comes from Kevin Tracey with Oberon AM. Your line is now open.
Great. Thanks for taking my question. Brent, in the 10-Q, there was a note that you acquired $17 million of coal inventory with the Merom acquisition. I understand Hoosier's original plans were to shut the plant next May. 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?
Yeah, I think your question was, do we have a lot of fuel post-May 2023? The answer to that is no. We do not expect that plant to operate much from, say, June to December 2023 with current fuel procurement. That could change, but that's the position we're in today.
Okay. The related question to that is I think the next capacity auction's coming up in April for the year starting June of 2023. Just given the, I guess, what you just said, kind of the lack of coal supply, at least for the second half of 2023, does that kind of prohibit Merom to enter into that capacity auction, you know, 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, you know, for the months in 2024, you know, when Oaktown can ensure coal supply?
Yeah, twofold. One, we do believe we have enough coal procured to meet our requirements. We also are working on, as I said earlier in the call, increasing our coal production. That's another way we can put more fuel to the plant. We can acquire fuel from other third parties. Those are all things that are on the table. No, we think we can fully participate in the capacity of auctions and markets in future years, 2023 and 2024.
Oh.
Yeah.
Okay, great. Just to confirm this kind of $39 million of advanced capacity payments from Hoosier, there's no, well, cost or cash cost associated with that, is there? Then you have the PPA built 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, well, additional capacity payments, you know, 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 and so. But yeah, I think we come back and say we've still got capacity to sell. We have a lot of interest from other parties, and you know, capacity pricing to date is very good. You know, 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. Capacity continues to tighten, and it is our viewpoint and belief that capacity becomes more valuable over time, not less valuable over time.
You know, we think that those are comments that are also being echoed by MISO directly. If you read what they're saying, I think they realize they've got a capacity shortfall in future years, and they are trying to, you know, modify their auction process to incentivize the market to slow down retirements and speed up additions of capacity. You know, we think from our perspective, that puts us in a position where in most years, a significant portion of capacity or a significant portion of our fixed cost of the plant can be covered by capacity payments. If that holds true, then, you know, from our perspective, we kind of get a free option to put, you know, fuel to the plant or fuel to the public. Now, you're right.
I mean, we can't put zero fuel to the plant, but we can vary that amount. You know, if third-party market is willing to pay a significant premium above what we think the power markets will bring. As evidence of that's what we did. Basically, in the Q2, you know, we agreed to those contracts in Q2. We signed those contracts in Q3 to sell it to the market versus take it, you know, take it to the plant. We felt that that was the, you know, best risk-adjusted return at that time, that was available to us. You know, realize at that time, you know, we weren't 100% sure we were going to close on the plant. We were, you know, 98% sure.
We were glad to finally complete that transaction. We're thrilled to have Merom in 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. You know, today, the plant is very much needed in the grid from a capacity viewpoint. In the future, you know, it gives us a great platform for investment in and to have our shareholder investment in, you know, new generation sources, which, you know, if I was sitting here today, I would tell you it'd be solar and battery. Time will tell.
Yeah. Okay. Just to clarify on that $39 million capacity payment and future capacity payments, there's no kind of cash cost associated with that revenue. You're just standing by with the capacity willing to provide it. Is that right?
Yeah. 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 you know, by selling your capacity, you basically are saying, "Hey, look, I've got an asset that's ready to go.
I've got, you know, the employees, staff to make it operate, and I've got fuel procured and in position with my inventory and existing contracts to be able to meet the capacity factor that we think that plant will run at." We are in position to say yes to all those things in 2023 and beyond. What we are trying to say-
Brent, even though we don't.
Even though we don't have correlated expenses related to that capacity income, we do have fixed costs at the plant in order to bid that capacity into whoever is buying it or the market.
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. In the past coal CapEx has kind of been more in the $30 million-$35 million range. I guess I'm just curious next year, what are you thinking? If you have any comment on what Merom's kind of normalized CapEx will be that'll add to the company, that'd be great. Thanks.
Yeah, we expect our coal CapEx going forward to be at $35 million-$40 million range. Could be a little higher next year, even with the surface equipment ramping up the two surface mines we have. Our CapEx at Merom, we have two categories of CapEx there. We have you know, just regular reliability maintenance CapEx that'll be in the $15 million-$20 million range. We have to start analyzing our ELG you know, to get into the effluent limitation guidelines with that plant by 2025 and when we will start that process and it's about $40 million-$45 million over the next three years. 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.
Got it. Okay. Thank you. Appreciate it.
Once again, if you'd like to ask a question, it's star one on your telephone keypad. Our next question comes from Ted Waters, a private investor. Your line is now open.
Hi, Brent. Thanks for taking my call. 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 2024 megawatt hours 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 dollar tons in Q3. If you were to sell into the megawatt hours in 2024 today, what pricing is that putting today?
Yeah. The answer to that 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, you know, 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. You know, that changes every day, right? Every hour within the day. We do have curves that, you know, kind of show, hey, where it thinks the power market, you know, is going forward. You know, it's. I don't know if I'm ready to release any of that from proprietary perspective.
As far as at the plant, basically 1 ton of Oaktown coal at the Merom plant generates about 2.2 MWh, right? If you take, you know, there's various curves out there and various assumptions, but if you take a megawatt hours , the variable cost on that, you're gonna have about $5/MWh variable cost. You know, let's just talk for easy math. If a megawatt hours was $50, and it's the equivalent of 1 ton of coal is gonna produce, you know, 2.2 MWh, so that's a $110 per ton equivalent. Subtract $5 in variable. Excuse me, I've double dip there. So $10 now. Now you're, you know, roughly at a $100, $100 coal. Then what's your fixed cost at plant?
Is the capacity payment covering your fixed cost to the plant or is it short or is it long? Is capacity payment exceeding fixed cost to the plant? That's kinda how we look at it. Hope that made sense.
Yeah. That I assume now that's how the math you do when you decide to sell it 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. You know, there's some requirements with that, right? I mean, you know, there could be letters of credit that are required from the counterparty to kind of secure and guarantee delivery of those electrons. Those are all things that we have to kind of look at and keep it balanced. You know, look, there's been a lot of disruption in the energy markets with what's going on in Europe, right? You've got a lot of coal and natural gas or LNG flowing to Europe.
Domestic coal is competing with that. You know, if you look at it right now, you know, gas is cheaper than coal, but the market needs all the coal generators to run. You've kind of got, you know, coal generators, in our opinion, setting the price of power. That will happen as long as demand exceeds all the gas generation and gas prices stay where they're at. There's a lot of dynamics 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 on the open market.
You know, we're happy with the position that we're in as far as getting the company net debt-free and, you know, contracting for capacity and energy at prices that we think we can make profit at. That's where we're at.
Our next question comes from Arthur Calavritinos with ANC Capital. Your line is now open.
All right. Thank you. Let me ask you something on the debt reduction to zero. That's gonna happen. You've got that locked in for this year, right?
Not quite sure what you mean by locked in.
It's gonna be paid off. I mean, you know, 95% confidence interval. You know what I mean? I mean, given what you're looking at right now, we're not gonna get any surprises, you know, 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, you know, be de minimis, right, by year-end?
Yeah. I think from our perspective, we've contracted for the coal, right? We know that our average sale price is going to come up significantly. We're gonna see, you know, significantly higher margins, something in the low 20s%. We have to produce the coal, which we've always historically been able to do. 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. You know, we're forecasting a higher cost per ton moving forward. You know, we're reliant upon our customers providing transportation to pick up the coal, which that piece is out of our control. It's in our customers' control.
From a forecast perspective, we see no reason why we shouldn't be, you know, materially net debt-free by the end of the year.
Okay.
I'm sorry.
By the end of.
I wanna be clear on that.
By the end of 20.
2023.
2023. Yeah.
When you guys are looking at projects, right, internal rates of return, you know, with the businesses, any, I don't know, discipline or are you seeing better opportunities? You mentioned storage. Again, you know, it must be difficult to, you know, to do a spreadsheet to model that out. 'Cause what I'm concerned about is I don't wanna see you guys do, like, a lot of storage or something and, you know, it doesn't work out. That's all. 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.
Yeah. I think our focus right now is that we are essentially long energy, long capacity, and we're at a pretty good sales position. If you look at us forward 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. There's various ways to do that, some of which require some amount of capital. What we're saying is look, 2023 is about getting our balance sheet in a very delevered position and trying to position the company to have profitable power capacity and fuel sales in 2024. That's kind of what we're focused on.
When we talk about energy storage, you know, the Inflation Reduction Act was released and approved this year. However, they're still writing some of the technical rules around that. 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, you know, is that, is that a good rate of return for us or not? Today, I couldn't tell you yes or no. Right?
Okay.
We'll wait 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, right? I mean, what solar developers and battery developers are dying for is a place to plug into the grid. The MISO queue study has been backed up four years. PJM queue study is so far backed up, they've stopped accepting applications. We don't have to do a queue study. We already own the interconnect. We already have rights to that interconnect today.
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, you know, 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 won't even accept the application. In MISO, they'll accept the application, but they might be four years. If your application happens to be on the edge of MISO's grid near another ISO, both ISOs have to approve that application. That's, you know, I mean, one of the things that's causing a problem with this transition from fossil to renewables is there's not enough places to plug in, right?
We're turning off generation. It has an on switch. We're turning off generation that can run 75% of the hours in a given year, and we're replacing it with generation that cannot be turned on from a grid operator's standpoint, and it's only going to run 20 hours, 20% of the hours in a given year. That's the challenges that the grid is seeing today. You know, I spent some time last week with a couple different grid operators who basically outlined, "Hey, look, the number of levers we have to pull to keep the system in balance is being reduced." Which then leaves them as demand response is the new lever they're looking to reach for. Well, demand response is we're shutting power off to someone, right? That's what demand response is. Who is getting their power shut off?
Hopefully, they've agreed to that ahead of time, but that's not always the case. For all those reasons.
Yeah. Yeah. Okay. Go ahead.
Yeah. For all those reasons.
Yeah
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 ELGs to run beyond 2025. We look to make those investments in that 2023, 2024, 2025 period to be in position to do that. That is our thinking today. We've not pulled the trigger on that yet, but that's what we're evaluating in real time. We think this asset becomes more valuable because of the attributes it can provide to the grid and because there are fewer and fewer generators that have these attributes that are available to the grid.
You know, the motivation of a public utility is very different than a wholesale power generator, which is what Hallador Power, our subsidiary, Hallador Power that owns Merom, that's essentially what it is. For those reasons, you know, that's what we look like, and this is where our thinking is.
No, got it. Thank you. One last thing. We're like, I was gonna say, we're in Boston, so we're gonna have like some. We've already had shutdowns in the summertime, you know, the industries nobody cares about. But if we get some shutdowns, national news type of stuff, like in New England, right? Where it's really tight. I'm just thinking how you, like, where you guys are, let me more specifically ask. Would legislation or regulation change to be more favorable to you as people realize or, you know, finally the regulators realize how, and the citizens, how valuable these things are? We're gonna have problems.
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, right?
Welcome, yeah.
Yeah. We've seen this happen. Look, every grid that approaches 30% renewables crashes, right? We've seen multiple crashes in CAISO. We've seen it in Texas, the energy capital of the United States. We've seen a five-day outage that cost over $200 billion and 100 people lost their lives. We saw Texas make massive changes to the rules around power generation in ERCOT, right? The Electric Reliability Council of Texas.
Mm-hmm.
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 saying, "Our plan is to be backed up by PJM. PJM's 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's gonna have a bad day." I mean, that's a public quote from the chief operating officer of MISO. 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, you know, trying to reduce climate change, but there's new risks that are associated with that. 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 right to shut it down when we want to convert it to something else. We're going to let the economic market decide. Right now, the signals are telling us this plant should remain online, and we should continue to invest on it. That's, you know, that's where we're headed today.
Okay, great. Great commentary. Thank you very much.
Thank you.
Our next question comes from Andrew Love with Hallmark. Your line is now open.
Thanks. Congratulations on a good quarter. My question is, could you explain 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?
You're a load following member of the grid, which means, you know, I have, you know, 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, right? MISO basically says, "If you want to buy a gigawatt worth of power in any given hour, you have to supply MISO with a gigawatts of rated capacity." There's all sorts of different ratings on power plants. Merom's nameplate is 1,070 MW. It will actually produce, you know, somewhere around 960 MW in any given hour. Its rated capacity with MISO today, which changes every year, is 917 MW, right?
We can sell because we are not a load following member. We do not have customers that we're selling electricity to. We don't have rate payers. We're a wholesale power generator. Since we are not buying electrons from MISO, we have no obligation to provide them capacity. Yet we have capacity. 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.
If somebody wants to buy 100 MW worth of electricity from MISO in 2023, for the 2023 calendar year, which is June 1st, 2023 through May 31st, 2024, they could come to us and say, "All right, Hallador, we would like to buy 100 MW of capacity from y'all, and here's the terms of the deal," that you know we agree to. en you've sold that.
What does that obligate us? What does that obligate us to do? That obligates us? It obligates Hallador to bid in its plant into MISO each and every day, which basically says we send a message to MISO saying that, you know, for tomorrow, we're willing to bid in at these hours this many megawatts at these prices.
You must have an obligation.
If our price is low.
You must have an obligation to meet some price criterion, otherwise it doesn't mean anything.
Correct. There are parameters about what price we can bid in. I think the limit is up to three times our cost. Or we can bid as low as we want, right? We could bid at a loss if we so choose.
If they accept it, you must deliver.
Correct. We get paid. Let's say we bid in at $40. 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. We're told to turn on. All MISO is doing is matching demand to supply. Think of it like a layered cake, right? Where, you know, you've got the wind operators maybe bidding in at $5/MW. You've got the solar guys coming in and saying, "Look, we'll provide at these hours at $6/MW." You've got the nuclear plant saying, "Hey, we're either on or we're off.
We're going to be on, so we're going to bid in at $10/ MW. Then now you have the assets such as gas and coal coming in higher up the stack and, you know, bidding in. What MISO is saying is, "Hey, look, we're going to bid this all the way up until we get enough generation to meet load." But everybody gets paid the highest price for that particular hour.
A follow-up. All in all, what was your prediction of CapEx for 2023?
Yeah. It was 35-40 on coal, and it was about 15-20 for reliability at the plant, and then around 17-18 for ELG.
ELG means what?
Effluent limitation guidelines that the EPA put out a few years ago that we have to be in compliance with by 2025.
Oh, 2025.
That's roughly $40 million-$45 million over the next three years. And so.
Okay. Thank you. Thank you, Andrew.
Our next question comes from Jeff Bronchick with Cove Street Capital. Your line is now open.
Good. Thank you very much. Good afternoon, gentlemen. Just quickly, out of the $150 million in EBITDA, quote unquote, "expected in 2023," is that all coal, or does that include the, you know, capacity payments from Merom?
No, no, that includes the capacity payments from Merom. The majority of our EBITDA in 2023 will be coal because of the PPA we've entered into, and the fuel limitations for the plant.
Got it. When you say the capacity payments, you know, will basically enable you to run Merom at breakeven and then, you know, you get, you know, all the optionality, is that on an operating basis, or is that in a cash flow basis including that $15-$20 maintenance and then the ELG payments?
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, right? We get capacity revenue, which in 2023 we anticipate will mostly cover nearly all the fixed costs of that plant. We have a fair amount of power sold to Hoosier in January, February, March, April, and May, but that's at a relatively low price. We make a margin on it, but we don't make a huge margin on that. We are more unsold starting in June through December of 2023, but we don't have a lot of fuel to put to the plant.
We don't expect, even though we can make potentially more money on a per megawatt hour basis, 'cause we could sell electrons at a higher price, we currently don't have a lot of fuel bought. We have some fuel bought, enough to meet our requirements, in 2023. All we're trying to signal is that we don't anticipate, today, 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 to Merom, and we can sell that. We can sell electrons out of Merom either on the day-ahead market or through a bilateral sale to, say, a public utility or a trading company.
We think, judging by where we forecast prices to be today, that we can make a good margin in that in 2024. We've not put out any forecast for 2024 results, but
I got it. The maintenance, you still have to spend $15-$20 whether you run the plant or not, unless you know, truly close it down for good, right?
Correct. What we're saying is that, you know, Hoosier was in the mode of, "We're gonna shut this plant down.
Right.
They, as you do, did not spend as much money on maintenance of the plant here in the last nine to 12 months. What we're saying is we've got some maintenance, elevated maintenance expense on that plant to kind of get it in better condition than it's in today. We've got some money that we need to spend to become ELG compliant. As far as environmental controls, this plant has, you know, most everything you need to meet today's compliance requirements, but it does not have an effluent limitation guideline control system. That 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. Then race to get in compliance by the end of 2025. For the 2026 year. We wouldn't do that expense if we didn't plan to run the plant beyond 2025. You know, we feel we can make money at it. You know, quite frankly, we think this has put our company in a much better position in that, you know, our coal is not the most liquid market, right? 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 opens and closes so often.
If we take our coal to our plant, we can sell electrons every day in the day-ahead market. I mean, we have dramatically improved the liquidity of our revenue stream with the acquisition of the Merom plant. We have had
Got it.
Dramatically improved. Yeah, go ahead.
No, I understand. I think I get what you're getting at. That sort of, in a similar way, answers my next question of, you know, really—I mean, it was either this plant was 100% closing or you were the only guy because, right? Because you obviously, you know, it's a story of life of, you know, if you could sign ten-year contracts at $125 a ton, you know, one would do that. Conversely, your customers wanted you to sign ten-year terms at $32 at the bottom. I guess that's really your answer that, you know, look, we need to, you know, we should be balancing, you know, the world, and not every day is going to look like it does today.
Ergo, we should be, you know, we'll sell 2 million tons at $125, but we're always looking for ways to de-risk and take less for longer duration. Merom it fits into that game plan. Is that Am I getting that right?
Well, I think the plant gives us a lot of optionality, Jeff. I mean, which I think is what you're saying is that the fuel market, our traditional market, that's still available to us. 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, right? 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.
It was very easy to just say, "No, we're gonna sell this on the open market. We're gonna 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. We're working on some ideas, but, you know, keep in mind, we've owned this plant now for less than a month. You know, 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 gonna buy this thing? When is it gonna happen? Those questions are behind us now.
Now conversations with third parties are much more meaningful. You know, we're hopeful that we can transact in a capacity that adds to the EBITDA that we're projecting for 2023. 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. 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. You know, 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.
No, got it. Okay, just my last thing for the call. This and that. You know, this is a bold scheme, thoughtful, interesting optionality. Get it, you know? Could work really well, could be a neutral, could be a complete time-sucking mess. You know, life is full of uncertainty. My point being is that, you know, I would say this. You got a grant for an RSU plan that is just time-weighted.
I would say, if I were you and I were the board, I would have doubled or tripled the RSU package, but I would have made it, you know, committed to either, you know, 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, you know, bold and fruitful. It would dock you if it's, well, gave it a whirl, didn't work, as opposed to just, you know, kind of waking up and getting three-year time-vested RSUs. Would be my mental comment, which you don't have to address, but I would just throw that in your lap.
Well, I will say.
Okay, go ahead.
Our executive team's RSU are based on metrics based on both EBITDA and.
Yeah, the annual numbers. Exactly. Short term.
Yes.
Yeah. I mean, I don't like to argue and say a CEO should be paid more. That's, you know, that's a winning argument for you, so you should just take it as is. I appreciate your time. Thanks.
All right.
Okay.
Our next call comes from Lucas Pipes from B. Riley Securities. Your line is now open.
Yeah. Thank you so much for taking my follow-up. Brent, you spoke about the converts in your prepared remarks. Just maybe as you think about potential, you know, future sources of capital, would you be open to more converts or might you look to other sources at that point? Thank you so much.
Well, I think at this juncture, you know, we are significantly deleveraging our balance sheet. When we did the convert, it was at a time where our EBITDA performance was poor. Yet at the same point in time, we were knocking on the door of all this opportunity. To take advantage of the opportunity, and when I say opportunity, that is sell coal at high prices, increase production, acquire the Merom Power Plant. Those are kind of the three things that were laying in front of us. To take advantage of that, we knew we had to spend more money on CapEx, and we couldn't really rely on any more of the debt market. 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. I don't, at this juncture, look to do any more converts, and we just look to deleverage our balance sheet and work on, you know, continue to create cash flow streams for the Hallador shareholder.
Got it. Very helpful. Maybe just one more from 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? Maybe just how are discussions progressing with these rail providers as you're kind of looking to return to higher levels?
Yeah. It's kind of customer by customer. Some customers are doing really well at picking up what they're required to pick up, and others are not. We're in communications with both of those. We have, you know, I would say performance on that front has been, you know, more of the same.
Got it. Fair enough. Well, thanks for all the color and continued best of luck.
All right. Thank you, Nick.
There are no further questions, so I'll pass the call back over to the management team for closing remarks.
Look, I appreciate everyone taking the time today, you know, we're very excited about the future of Hallador and the position that we're in. You know, we see as much opportunity in front of us as I think we've ever seen in the history of our company. We're excited about that, you know, we think we've got the management team and getting the capital structure in place to take advantage of those opportunities. Look for more interesting things out of us, and look forward to talking to y'all next quarter. Thank you.
That concludes the conference call. Thank you for your participation. You may now disconnect your lines.