Hallador Energy Q3 2023 Earnings Call Transcript

Quartr
Provided by Quartr
November 7, 2023

There are 9 speakers on the call.

Operator

Everyone and welcome to the Hallador Energy Third Quarter 2023 Earnings Call. My name is Emily and I'll be coordinating your call today. After the presentation, there will be the opportunity for any questions, which you can ask by pressing star followed by the number one on your telephone keypad. I will now turn the call over to our host, Rebecca Colombo. Please go ahead.

Speaker 1

Thank you, Emily. Thank you everybody for joining us today. Yesterday afternoon, we released our Q3 2023 financial and operating results on Form 10Q that is now posted on our website. With me today on this call is Brent Bilsland, our President and CEO and Larry Martin, our CFO. After the prepared remarks, we will open up the call to your questions.

Speaker 1

Before we begin, Please note that the discussion today may contain certain forward looking statements that are statements related to the future, not past events. In this context, forward looking statements often address our expected future business and financial performance. While these forward looking statements are based on information currently available to us, if 1 or more of these risks and uncertainties materialize Or if our assumptions prove incorrect, actual results may vary materially from those we projected or expected. For example, our estimates of mining costs, future sales, legislation or regulations. In providing these remarks, we have no obligation to publicly update or revise any forward looking statements, whether as a result of new information, future events or otherwise that may be required by law.

Speaker 1

For a discussion of those risks As a reminder, this call is being recorded. In addition, we will have an archived webcast of this earnings call on our website. We encourage you to ask questions during the Q and A. And if you are on the webcast and would like to ask a question, You will need to dial into the conference line. That toll free number is 1-eight 33-four 701428, And with that, I'll turn the call over to Larry.

Speaker 2

Thank you, Becky, and good afternoon, everyone. Before I begin, I want to define adjusted EBITDA, Which we define as operating cash flow less the effects of certain subsidiary and equity method investments, Plus bank interest, less the effects of working capital changes, plus cash paid on asset retirement obligation reclamation, Plus other amortization. For the quarter, Hallador incurred net income of $16,100,000 which Was $0.49 a basic earnings per share or $0.44 per diluted earnings per share? For the year, net income was $55,000,000 a $1.66 earnings per share, dollars 1.52 diluted earnings per share. We had adjusted EBITDA for the quarter of $35,900,000 and for the year, dollars 105,200,000 We decreased bank debt by $12,500,000 for the quarter, dollars 23,500,000 for the year.

Speaker 2

Our funded bank debt as of September 30th was $61,800,000 We had letters of credit totaling $11,200,000 And our net funded bank debt was 59.2%, which is funded or bank debt less cash. Our leverage ratio, which is defined as debt to adjusted EBITDA, was 7.1 times at September 30. Did I say 7.71 times for the quarter. I will now turn the call over to Brent to review the quarter and beyond.

Speaker 3

Thank you, Larry. First, I'd like to thank the Hallador team for their hard work and dedication On creating another successful quarter, as I've highlighted in our previous quarters, our goals of increasing profitability, Increasing company liquidity and reducing balance sheet leverage remain paramount to how we operate as a company. This quarter's results show our continued progress towards these goals. Our net income £16,100,000 for the quarter helped build on our record net income of £55,000,000 for the 1st 9 months. And our continued record operating cash flow of $79,500,000 over the 9 month period Has allowed us to invest $48,700,000 in capital expenditures to improve our efficiency and reliability At both our mines and our power plant.

Speaker 3

We made continued progress on our goal of improving our balance sheet By repaying CAD23.5 million of debt during the 1st 9 months of the year, CAD12.5 million of which Was during the Q3. This further reduced our leverage, as Larry said, to 0.71 times, While we increased liquidity to $66,400,000 as of September 30. On October 2, we successfully amended our credit facility with P&C Bank, Which we accounted for as a debt extinguishment. This amendment is important as it extends the maturity of our credit facility into 2026. During the Q3, high coal sales prices coupled with large coal shipment volumes Led to record coal revenue.

Speaker 3

Our well contracted sales book supported our revenue growth despite Operational challenges increasing our cost per ton during the quarter. We chose to relocate 57% of our Coal units of production during the Q3 and into October to better to obtain better geologic conditions. This led to higher cost and decreased production during this time frame, but it was resulting in overall production improvements Following the moves, which we expect to continue. During the quarter, we shipped 2,100,000 tonnes of coal At an average price of $56.43 before intercompany eliminations. We produced 1,600,000 tonnes in the quarter at $46.54 per tonne Before elimination, leading to margins of $18.89 per tonne during the Q3 before elimination.

Speaker 3

We expect an average price of $54.30 per tonne on the remaining tons to be shipped this year. On the power side of the business, intercompany coal sales from our coal division to our power plant division Increase the average variable cost per megawatt hour to $40.03 per megawatt hour, an increase of $9.98 Per megawatt hour over the prior quarter before elimination. We set the price of coal we sell to ourselves Based on 3rd party market indicators that we review from time to time, cost per megawatt hour were 23 And $0.49 on a consolidated basis. As the marketing price fluctuates, We expect to see these types of variances in each side of the business. During the quarter, we produced 1,300,000 megawatt hours.

Speaker 3

We are excited about the progress we are making in our forward power sales capacity book. During the quarter and in the time leading up to this release, our Power division was successful in securing $325,000,000 of energy and capacity sales across multiple years as reported in our Form 10 Q filed last night. This morning, we received a signed agreement for an additional $41,000,000 of capacity and revenue Over the years 2024, 2025 and 2026, bringing this number of total sales up to 366,000,000 These sales are important as they create a profitable foundation for our Power division over the next 5 years with sufficient energy sales At excuse me, with significant energy sales at $56 per megawatt hour and capacity prices approaching $2.20 Per Megawatt Day. Now we get a lot of questions concerning how an investor should think about Hallador

Speaker 2

Now that

Speaker 3

we have added a power division. To add clarity, we included a detailed section We included a lot of detail in Section 3 of the overview of the MD and A, outlining our Sales of coal, power and capacity through 2028. At a high level, I think about our business as such, We produce 7,000,000 tonnes of coal annually. Just over 4,000,000 tonnes Is sold to outside customers and almost 3,000,000 tons is sold to our power division, Hallador Power. The reference table will show that over the next 5 years, 54% of the coal that we plan to sell to outside parties is already committed to those parties and 73% of these commitments are priced at an average price of $52.60 per tonne.

Speaker 3

Our year to date cost per tonne to produce coal was $43.25 The other 3,000,000 tonnes assume that we will annually produce 6,000,000 megawatt hours at our power plant. Now there are rules about how we price this coal to ourselves, and the accounting around this can be confusing to follow due to However, the price that is chosen for the coal that we sell ourselves only determines how much profit or loss is allocated To our coal division or our power division. Ultimately, what matters is how much profit is made at Hallador based on our cost structure. During the Q3, our consolidated variable cost at the plant Was $23.49 per megawatt hour. As stated in previous quarters, we use our capacity sales Cover the majority of our fixed cost at the plant.

Speaker 3

We have sold and we expect With the capacity prices that we're seeing that to continue. We have sold approximately 27% of our future power through 2025 at 30 $4 per megawatt hour, roughly a $10 margin based upon that cost structure. But in this past quarter, we have sold 3,300,000 megawatt hours for the 26, 20 27, 20 8 years at $56 per megawatt hour, Which is roughly $32 per megawatt hour profit margins based on today's cost structures. These sales have us very excited about the profit potential for Hallador Power. Now that Doesn't mean there won't be operational challenge such as the one we experienced on October 2, when we had an unplanned transformer outage And one of the generators at the power plant.

Speaker 3

The transformer has since been replaced, in the event will cause us to miss A net 2 to 3 weeks of output from 1 of those 2 units. I want to reemphasize, I'm very excited about the future of the company, especially as I look to the power sales through 2028. What we are seeing through increased pricing from our recent power PPAs, Coupled with strong capacity, demand and pricing, with the solid book of business that we are now showing and the steady supply of coal from our mines, I am incredibly pleased with the progress that we are making towards leveraging the opportunities that drove our decision to acquire the power plant. As I said at the start of my comments, I'm encouraged by the quarterly results and the continued progression of Hallador as a company. And with that, I will open up the call for questions.

Speaker 2

Before we go to questions, I want to clarify one sentence here. Our shipments were $2,100,000 at $65.43 for the quarter for an $18.89 per ton margin.

Speaker 3

Thank you,

Operator

We will just pause for a second to allow the questions to come into the queue. Our first question today comes from the line of Kevin Tracey with Oberon Asset Management. Kevin, please go ahead. Your line is now open.

Speaker 4

Great. Thanks for taking my questions. The first one is just to clarify What I thought you just heard you say about the outage at Miriam. So in the 10 Q, there's a note It says the unit isn't expected to be back into service till the second half of December. So, but I thought I heard you say that the Outage was only 2 to 3 weeks.

Speaker 4

So I guess was it are we kind of missing 2.5 months or 2 to 3 weeks of this unit?

Speaker 3

Yes. Let me clarify that. So the unit was already scheduled to go on a scheduled outage From November 1st to December 27. Okay. That's something that we scheduled with MISO, Yeah.

Speaker 3

I'm 6 to 9 months in advance, and we bring in outside contractors to do routine maintenance On the unit. So that was planned. The unit went down basically a month early, due to the transformer. And so we have sped up, part of the outage work To begin some of that work that we could do in October, which means instead of the unit coming back online, It's December 27th. It'll probably come back online a week or 2 earlier than it was previously scheduled.

Speaker 3

So net net, We're going to lose this unit, 1 of the 2 units for 2 to 3 weeks longer than was expected and planned for.

Speaker 5

Okay. And cross your fingers,

Speaker 2

the power prices are up here in December.

Speaker 4

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

Speaker 3

Yes. I think every time you have a forced outage so accreditation is a rolling 3 months It's a 3 year process, right? And so they're looking at your performance history during that timeframe. So things that help your capacity rating are, we acquired a plant that was Scheduled for shutdown. So some of that maintenance was let go.

Speaker 3

And we are Spending additional monies this year and next to kind of get the plant back in what I would call tip top shape. And so where that helps you on accreditation is we're seeing higher output numbers Then when we took over the plant a little over a year ago, right, so as you get newer and better and refurbished equipment on the plant, You're able to achieve higher performance. That's to the good side. The bad side is every time you have A unscheduled outage such as we had with the transformer, That counts against you in accreditation. And then I'd say, thirdly, we still see MISO Making tweaks and adjustment to their accreditation process.

Speaker 3

They've not finalized those rules. And so we can't ever be 100% certain What comes out of that? Do we get more accreditation? Do we get less accreditation? It's always hard to say.

Speaker 3

So All we can do and then what we have done is, as of our last accreditation, which was 800 and I mean, it's on a seasonal basis, but I think on average, Our accreditation was 8 60 megawatts. That's what we're basing our numbers on. So when we show you, Hey, here's how much capacity we've sold as a percentage of the plant. It's based on an assumption that our accreditation is 8.60, But that number could go up or down based on our next accreditation from MISO.

Speaker 2

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

Speaker 3

Yes. Odds are we're going to have colder weather in December than we had in October. Power prices Theoretically, it would be higher in demand. So it may not be as We may be trading 4 mild weather weeks for 2 cold weather weeks. We just don't know.

Speaker 3

We won't know until we get there.

Speaker 4

Understood. Okay. And then so with these power Sales agreements you've entered and you've sold about a quarter of your planned generation for the next several years. Can you talk a bit more about How high you want to go in terms of selling PowerForward as a percentage of your expectation? And then how are you managing The risk there or if the plant were to have an unplanned outage and you've agreed to supply power At certain prices, you could find yourself along the power market.

Speaker 4

So how are you kind of managing Risk when you're thinking about entering those agreements and if you could touch on how high you're hoping to go in terms of forward sales?

Speaker 3

Yes, good question. So far to date, everything that we have sold on the power side Is plan or unit contingent, meaning that we've sold the power, and if we fail to We do not have to go out and buy that power. We don't have to cover, right? We just simply Are not shipping those electrons to the customer, and they either have to do without or they have to go buy them elsewhere. But that is not On our account.

Speaker 3

So I think as excited as we are about our sales on a risk adjusted basis, we're extremely excited about that. We'll look to see what opportunities are for these are bilateral agreements. These are not Exchange hedges, on an exchange head, that's a firm power sale. We would have to cover in that scenario. And so we want to make sure that we have a lot of liquidity if we do that type of hedging.

Speaker 3

And so part of our process and what we've talked about here is we want to make sure we get our balance sheet as healthy as possible, Get our liquidity as high as possible, and then we'll look to the market to see if there is hedges that we want to Additional hedges that we'd like to layer in.

Speaker 4

Okay. And then on the mining cost Sorry, go ahead.

Speaker 3

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

Speaker 4

Got it. Okay. And then on the mining cost per tonne, so I think heading into this year, The hope was that we would see an improvement over 20 22's $37 per tonne. We've obviously seen costs Rushed quite a bit from there. Can you talk about what went wrong versus your expectations?

Speaker 4

Was it just And general inflation or an issue with the geology? And you made some comments about improvements you're From some changes you're making, can you help set expectations on where you think your mining cost per tonne will be for 2024?

Speaker 3

So on the production outlook, It's pretty we have 7 units, 7 individual production units underground. I think it's pretty typical in any given quarter for 1 or 2 of those to be struggling. What was unusual about this quarter is we had 4 units struggling. And we Sometimes that catches you at a time that's a little out of sequence to be moving. Yes, you fight that for a little while, and then finally, ultimately, you come to the decision of we need to shut the unit down and move it.

Speaker 3

And there's just Lost time and production when you do that, particularly out of sequence like we did this quarter and into October. So very unusual to move 4 units in any given quarter, but that's what we did. And that's Ultimately, we had an outsized factor on why our costs were the highest they've ever been in any quarter in the history of the company. So disappointed by that. All I can say is we've moved those units, and I'm pleased with The productivity that I'm seeing to date out of those units, so we expect our cost structure To be better in the future.

Speaker 4

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

Speaker 2

I think that

Speaker 3

I think we will we have seen inflation. So I think Probably in 2024, gosh, some of that's going to depend What the production levels are at each mine, but I think you'll see us back into the low 40s, upper 30s.

Speaker 4

Okay. And then on the CapEx, so your 4th quarter guidance implies that the full year CapEx I'll come in about $10,000,000 than your original budget. And it looks like All of that delta from your original guide is coming from the coal business. Can you talk about where you think CapEx will end up kind of on a normal basis for the coal business going forward. And then do you have any update On the effluent project at Miriam and kind of where you're thinking the CapEx budget is going to look like next year?

Speaker 2

I'll handle the coal part and then Brett can answer the affluent question. But for the coal plant, we just had some with our moving things around the 57% we moved, we had Mine development we had to do and then we had some equipment that came on that's going to come on at the end of the year that we thought was going to be in The next year. So that's our $10,000,000 difference. Going forward, I think our plan is 35,000,000 For CapEx for the coal plant.

Speaker 6

Do you want to talk about ELG?

Speaker 3

Yes. On ELG, so The EPA has proposed a new rule that has yet to go final. So we are waiting to see where they ultimately end up, and we expect them To finalize that rule in this coming spring. And so that ultimately will decide what we do and the exact Timing and compliance date to meet that rule. Our Board has approved $45,000,000 to spend on that.

Speaker 3

We still feel comfortable that, that will meet where we think the EPA is heading with that rule And their most stringent standard, but we'll wait to see Where they end up on the final rule before we comply with that. So that is delaying the expenditure of some of those dollars Until we know exactly what the EPA wants.

Speaker 4

Okay. And the last quick one here. On the last call, your latest update on your target of getting to basically 0 net debt Was the Q2 of next year, is there any update to that guidance?

Speaker 3

Yes. I think the higher cost that we experienced this quarter is going to push that out at least a quarter and into the Q3 of 2024.

Speaker 4

Okay. All right. Thanks for answering all those.

Speaker 3

Yes. Thank you.

Operator

Our next question comes from Kevin Pounds with the Castlebury Advisory. Please go ahead Kevin. Your line is open.

Speaker 6

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

Speaker 3

We really saw a pretty mild summer. I think we had 2 weeks of Hot weather, so we saw good pricing during that time frame, but the balance of some per was From a power pricing perspective, it's fairly anemic. So we're still kind of waiting for You know, more colder days or hotter days, but we don't like 65 degree days From a business perspective.

Speaker 6

Right. There's been on the West Coast here, there's been refineries closing. Are there Some other older power plants that are in your area that might be closing that would tighten up the market? Or have you seen anything like that?

Speaker 3

Yes, we did just have another power plant that closed last week in MISO Zone 6, which is the zone that we're in. We think the trend continues to be People are taking generation out of MISO that has an on switch And replacing it with generators that do not have an on switch. And as long as that trend continues, That should increase the value of capacity, and it's going to create Higher highs and lower lows in the power markets, right? Because renewables tend to give you electrons not necessarily when you need them. And so if we can be a generator that can provide electrons when they're needed, we think that We're going to see some days where there's some pretty extreme high pricing.

Speaker 3

And when we have an open position such as we have today, Relatively open position. Then it affords us those opportunities to take advantage of that. So we'll see what the weather brings. And we continue each day to go to work to try to sell More power through bilateral agreements. And I think this quarter was a solid performance in that With I guess, if you include the contract we dragged in the door today, it was $366,000,000 of power and capacity sales.

Speaker 3

We keep having quarters like that. I think our investors are going to be very happy.

Speaker 6

Yes. Sherry definitely improved Earning disability and I know you've made similar comments before which sound prescient. We've had a lot of reports lately about these renewable projects Being too expensive and not delivering certainly the margins that people have wanted. Finally, you said you had 4 to 7 units that Struggled. Are some of those units maybe not going to be too high cost if we keep seeing cost Creep all over the country, not just you guys, obviously, with inflation and fuel and so forth.

Speaker 3

Yes. I thought it was interesting. There's been several mining companies that have reported before us, and it seems like everybody had a tough operational Q3, I'm not really sure why that is. I don't know if it was something about the A lot of humidity that came out of the mines as it cooled down or if it was just coincidence. But Certainly, everybody has seen cost pressure due to inflation, but I really think the majority of what we had going on this particular quarter and into October It was geologic and specific to our mines, and I think that we have solved that problem.

Speaker 3

And I'm sorry that the quarter wasn't better from an operational cost point of view, but I hope I think we've fixed the problem.

Speaker 6

Great. Well, thank you so much and keep up the good work.

Speaker 3

Thank you very much.

Operator

Our next question comes from Jason Lustig with J. Goldman. Please go ahead, Jason. Your line is open.

Speaker 5

Hey, thanks for taking the question. Just wanted to Thank you for increasing the disclosure in the contract table. Really helps, I think as another caller said, just better understand the long term economics of the company. So appreciate that. As I have thought more about this table, I think we're getting a sense for what the future revenues of the company can look like, the 3 different revenue streams.

Speaker 5

We have a reasonable sense of the coal costs per ton, the fixed costs we've talked about in the past at the plant. One thing that I'm struggling a lot with and would appreciate trying to better understand Is the variable costs per megawatt hour excluding fuel at the plant? And how we should think about that over time?

Speaker 3

Well, Look, I mean, fuel is the majority of it. I think we've come out and said that during the quarter on a consolidated basis, Variable costs, including fuel and nonfuel, was $23.50 per megawatt hour. I don't think at this time we plan to break out what our non fuel expenses. Quite frankly, I think we've got enough numbers that Our goal is to not confuse everyone. Our goal is to create as much clarity as possible, and that's why we spent A lot of time on that table I referenced, in an effort to try to get Everyone to understand, right, because it gets very confusing when you start pricing coal to yourself and you have these company intercompany eliminations, It's all GAAP.

Speaker 3

It's all the way it's supposed to be, but we're trying to clarify that, that, hey, at the bottom line, It was extreme it's just a great earnings potential at the power plant. And We hope everybody gets as excited about that as we are, particularly when our most recent pricing, Particularly on a risk free basis, since it's unit contingent, it is quite profitable. And so Anyhow, I appreciate your compliments on that. We're probably not on this call And I get into what our non fuel costs are at this time.

Speaker 5

Okay. Okay. I appreciate that. If I flip to the coal operations segment of the 10 Q, I see this as $37,000,000 in sales to the Mirim plant That are eliminated in consolidation. And I would love to try and triangulate and better understand how that I can reconcile that number with the $40.03 per megawatt error Cost at Merum, variable cost at Merum and the $22.49 consolidated number?

Speaker 5

And maybe that can get us most of the way there for those who are

Speaker 3

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

Speaker 5

I'm trying to I just we can do our own math I guess on the outside to try and lay any confusion, but I am trying to figure out how much I guess what was the cost of the price of the coal that was transferred and what is the right number? Is it 500,000 tons? I think I saw somewhere else in the 10 Q. Is there some other number that I should be using for this quarter? I can just Yes.

Speaker 5

So I think So I don't know if I can look at the right numbers.

Speaker 2

So everything's and I'll give you I mean, I'm not you guys can do the math, Here's the numbers. We sold coal to ourselves for $75 which is in the queue, so we have to eliminate that. And then our costs were 40 some I can't remember off top of my head where they're at in the queue, but then our costs for the quarter were 40 $6 I think. So that has to be that profit has to be eliminated as you sell The call to yourself. Now we did burn, but it's not just what we sold in sales, it's what we actually burned.

Speaker 2

There's some sitting in inventory that got eliminated as well.

Speaker 7

Okay. All right.

Speaker 5

I think that gets me most of the way there. Thank you.

Speaker 7

Right.

Speaker 3

Okay. Thanks.

Speaker 2

All right.

Operator

Thanks for

Speaker 3

your questions.

Operator

Our next question comes from Tom Kerr with Zacks Investment Research. Tom, please go ahead. Your line is open.

Speaker 3

Good morning guys or good afternoon. I think most of my questions were just covered. A couple of quick ones. As you guys continue to generate more free cash Refresh my memory if there's any restrictions on returning capital to shareholders through dividends, share buybacks, etcetera. No, at our current leverage ratio, we have no restrictions.

Speaker 3

Okay, great. And then lastly, you guys have indicated in the past that you may be looking further power plants for acquisitions to add to That side of the business, does that still look good? Is that still a plan or any opportunities out there you can mention? Well, nothing we can list specifically by name. We are always looking, and we think there's Hallador is in a unique spot to potentially take advantage of those opportunities.

Speaker 3

So certainly, we are looking.

Speaker 6

Okay, great. That's all I have

Speaker 3

for today. Thanks. All right. Thank you. Thanks, Tom.

Operator

Our next question comes from Lucas Pipes with B. Riley Securities. Please go ahead. Your line is open.

Speaker 7

Thank you very much, operator. Just a few quick ones from me. First, Brent, in terms of Struggling on the call side. What exactly is meant by that? What happened?

Speaker 3

I think we just you have units that run into bad roof. It could be that you've got presence of water or sandstone coming in close contact Our close location to the coal. And when we get that Sometimes you can fight through that and get to the other side of it. Other times, you have to back up, move over. Sometimes you back up, move over, back up, move over a second time.

Speaker 3

And then There comes a point where you just say, you know what, I'm going to move to a different portion of the mine and tackle this from a different angle or different Point of view. Moving over and attacking it again, that's pretty common. That happens. Major moves To a different area, that's pretty uncommon, and particularly for 4 units in one particular quarter. So I think we want to say that it was significant.

Speaker 3

It was unusual, and we think that that's behind us.

Speaker 7

Were all those 4 units working in close proximity when they encountered these difficulties? No. And the areas that you moved out of, are you going to move back towards them In due course or would you say kind of for the foreseeable future it was just too tough, you don't want to go back there?

Speaker 3

Yes. I mean, sometimes you just move around to the other side of it, right? There's a there could be a good Area of coal that can be a year or 2 of good mining, and you just need to access that from a different location. So it's not I don't want you to lead you to believe that we're abandoning large portions of our reserve. That's not the case at all.

Speaker 3

We are just attacking it from a different point of view.

Speaker 7

Got it. Okay. That's helpful. Thank you for that. And then I want to go back to your comments earlier on hedging versus bilateral agreements.

Speaker 7

And It sounded like there are certain advantages on these bilateral agreements. Does it come down to Force majeure provisions, is that really the difference?

Speaker 3

No. I mean, it's just It's pretty common to have either firm sales or unit contingent sales. And a bilateral agreement with particular customer is a very bespoke agreement. And It can have I would almost argue that no two agreements like that are exactly the same. Whereas, hey, if I'm just jumping on ICE And buying or selling a power contract, that's a very cookie cutter fixed agreement.

Speaker 3

It's different. And it takes on more risk, right? You can get a margin call if you're on ICE. I can't get a margin call from my customers. We have contingent powers.

Speaker 3

So from a risk perspective, I think we've put ourselves in a really good what we say is a good foundation of business. I don't know that we can sell all of our power under that particular Format? So we'll see. All we're saying is that we had great success this particular quarter, And we've got a great team that's out trying to get in situations that's both good for our customer and good for ourselves.

Speaker 2

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

Speaker 2

It's not really force majeure, but kind of.

Speaker 7

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

Speaker 7

Thank you. And then, yes, I really appreciate the disclosures. Quick question there on Page 18 of the Q. Contracted power revenue, that line shows $20,200,000,000 $98,050,000 That's pretty clear. The item immediately underneath it, what's how is that derived exactly?

Speaker 7

Can you walk me through that, the 43 point Before the revenue per megawatt hour, I don't clearly doesn't assume the 6,000,000 So I kind of struggled a bit to back into that.

Speaker 3

78% of 6,000,000

Speaker 2

So Lucas, that is the actual that's contract, what we have contracted for the year, Which is 78% of 6,000,000

Speaker 7

Got it. Got it. Okay. So it's not based on the $6,000,000 it's based on You've made an assumption you're running at, you said, 78% of the $6,000,000

Speaker 2

Well, it's what we have we don't have $6,000,000 contracts, but we have 1,000,000 we can provide. So the $98,000,000 is what we have contracted? Yes. For total that's total capacity and energy?

Speaker 7

Correct. Correct. And the line underneath it, the 43.34, would it step in?

Speaker 2

It's how much Revenue, we're it's how much revenue we're going to get on our contracted megawatts.

Speaker 7

But you have only $1,600,000 contracted now.

Speaker 2

But that includes capacity and power.

Speaker 7

Got it. Okay.

Speaker 2

I think what we're showing here is

Speaker 6

$43.65 divided by 70% of 6.9

Speaker 7

Yes, maybe we can take that offline, but I appreciate it. I I think I know where this is going, but maybe one quick follow-up. You have only $1,600,000 of output contracted, right? Correct. And so I mean the capacity payment you can still Yes, capacity payments, but you can still generate revenue on top of that, no?

Speaker 6

Absolutely.

Speaker 7

Okay. I appreciate that. Thank you.

Speaker 2

We have 4,400,000 Megawatt Hours of Power that we can still contract.

Speaker 7

Yes. Makes sense. Thanks, Dan. Hey, really appreciate all the color, and Again, best of luck. Thank you.

Speaker 3

All right. Thank you, Lucas.

Operator

Our next question comes from Roger Zeigler, who is a private investor. Roger, please go ahead.

Speaker 8

Hi, congrats on a good strong quarter despite some obstacle guys. My question is I've not had a chance to delve into the Section 3, you said it's related to power in general, this exciting new market. Am I reading the release that just posted the table the one of the tables that In 2024, you've got 27% of your power priced. Is that correct from the basic, the non GAAP Table that was provided in

Speaker 2

the 3rd quarter? At $34, yes.

Speaker 3

Yes. Yes, that's correct.

Speaker 8

So you've got 83% left to potentially there'd be some windfall times in there if possible, right? And then get extremes either way, as you said, that's pretty exciting.

Speaker 3

That'd be 73%. Yes. So basically what we think we've got Yes. We've got 27%, let's just call it 4th round map. We've got a 4th price, And we've got another 2 thirds or 3 fourths that we're open to.

Speaker 3

We bid into the market every day. And prices can be high and prices can be low. And prices can be so low that we take the unit offline. But we think we're heading into winter, and that typically historically has been some of the better pricing. We'll see what December, January February bring.

Speaker 2

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

Speaker 7

Correct.

Speaker 8

Okay. And a real general question may or may not be willing to answer, but I'll pick kind of a basic high level question. Are you finding it's very strong correlation to the natgas market for power as it is with coal?

Speaker 3

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

Speaker 8

Right. The coal to gas switching thing and vice versa, right. It's always in play, right. So And sorry, one last question on this topic then. One last question on this topic perhaps.

Speaker 8

Should we Regarding again the power market, are you mostly correlated to the Chicago hub, MISO Hub and even the nat gas in some way or is it more of like the summer with record heat throughout Texas for in the south for For upwards of a month, were you able to capitalize on that this past summer? Or is it more of a regional, Say, Indiana through Chicago, should we think of it in that those terms?

Speaker 3

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

Speaker 8

You weathered a bad summer that way. Chicago was as mild as it's been for forever, right? And we're right south of you. You had some heat. So let's hope for another Right.

Speaker 5

I mean, I Yes. I mean, I'm struggling with Finitex.

Speaker 3

Yes. We would love for the balance of that. Yes. So I was hoping for a bridge winter. Well, I think, look, we are very encouraged in that.

Speaker 3

There is a lot of new industrial demand showing up in the Midwest. Europe has had basically an energy crisis since So the Russian invasion of Ukraine, and that's causing a lot of re onshoring of industry. I was with politicians yesterday who More than one said, look, Indiana has a great business climate. We're not sure if we have enough people and we're not sure if we have enough power. And so Hallador being long power, likes to be in that scenario.

Speaker 5

We like where we're at.

Speaker 3

There's going to be some volatility to our earnings because we are we do have a large open power position, and that is subject to market movements. It'd be great. And there's a high end, there's a low end. But I think by and large, On average, we'll do really, really well. That's why we like the base of business that we're putting under it with our forward contracted sales.

Speaker 3

And we're encouraged by the most recent pricing that we saw at $56 a megawatt hour For multiple years. Great. Thanks

Speaker 7

so much. Thank you.

Operator

Those are all the questions we have for today. So I'll turn the call back to Brent for closing remarks.

Speaker 3

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

Operator

Thank you everyone for joining us today. This concludes our call and you may now disconnect your lines.

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Earnings Conference Call
Hallador Energy Q3 2023
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