Hallador Energy Co (HNRG) 2023 Q2 法說會逐字稿

Good afternoon, ladies and gentlemen. Thank you for joining today's Hallador Energy Second Quarter 2023 Earnings Call. My name is Tiaz, and I will be your moderator for today's call.

(Operator Instructions) I would now like to pass the conference over to your host, Rebecca Palumbo, Director of Investor Relations. Please proceed.

Thank you, Tiaz, and thank you, everybody, for taking the time to join us today. Yesterday afternoon, we released our second quarter 2023 financial and operating results on Form 10-Q. It is now posted on our website.

With me today on this call is Brent Bilsland, our President and our CEO; and Larry Martin, our CFO. After the prepared remarks, we will open the call up to your questions.

Before we begin, please note that the discussion today may contain certain forward-looking statements that are statements related to future, not past events. In this context, forward-looking statements often address our expected future business and financial performance. While these forward-looking statements are based on information currently available to us, if one or more of these risks or uncertainties materialize or if our understanding of assumptions prove incorrect, actual results may vary materially from those we projected or expected. For example, our estimates of mining costs, future sales, legislation and other regulations. In providing these remarks, we have no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise that may be required by law. For a discussion of some of those risks and uncertainties that may affect our future results, you can review the risk factors described from time to time in the reports we file with the SEC.

As a reminder, this call is being recorded. In addition, a live and archived webcast of this earnings call is available on our website. We encourage you to ask questions during the Q&A session. If you are on the webcast and would like to ask a question, you will need to dial into the conference number, and that toll-free number is 1 (833) 470-1428 access code 813157.

And with that, I'll turn the call over to Larry.

Thanks, Becky, and good afternoon, everyone. I'm going to go over the review of our operating results. And before I do, I want to make the definition here of adjusted EBITDA, which is operating cash flows plus our interest expense plus depreciation plus asset retirement obligation reclamation and other amortization and then less any effects of our subsidiary and equity method investments and less any effects of working capital changes.

So our net income for the second quarter was $16.9 million, which resulted in $0.51 per basic earnings per share or $0.47 diluted earnings per share. For the 6 months ended in June, we had $39 million of net income, which resulted in a $1.18 basic earnings per share and $1.08 diluted earnings per share. Our adjusted EBITDA for the quarter was $35.3 million and for the 6 months, $69.3 million. Our bank debt decreased by $1 million for the second quarter and $11 million for the 6 months. Our funded bank debt as of June 30 was $74.2 million. Our letters of credit were $11.2 million, and our net funded bank debt, which was our funded bank debt less cash was $71.9 million. Our leverage ratio, which is defined with our bank's debt to adjusted EBITDA was 0.94x.

So I want to turn the call over now to our CEO, Brent Bilsland, to go over the highlights of the quarter.

Thank you, Larry. Thank you, everyone, for joining today. Much like our first quarter, we remain pleased with the progress we continue to make during the second quarter towards our company goals of increasing profitability, increasing company liquidity and reducing balance sheet leverage. The realization of higher priced coal shipments led to (technical difficulty) Merom, without that, $20.96 despite higher production costs.

Coal production was strong, and we were able to meaningfully increase our coal inventories throughout the quarter. We intend to leverage this increased inventory to further supplement our power production and position ourselves to take advantage of the increased power needs anticipated in the summer months and throughout the second half of the year.

Additionally, on August 2, after the close of the quarter, we finalized a new credit facility led by PNC Bank. The highlight of this new facility is the improvement of our liquidity position to $56.9 million as of June 30. The strong sales from this quarter resulted in net income of $16.9 million in Q2 and the best net income we've had over the first half of the year at $39 million. This growth enabled us to make great strides towards our goal of deleveraging our balance sheet. As we continue to execute on our overall plans, we believe that Hallador has dramatically improved, both the quality of our business with the addition of Hallador Power last October and the quality of our balance sheet by reducing our debt-to-EBITDA multiple to 0.94x at the end of the second quarter.

Our coal business continued to thrive with an average sales price of ship coal during the quarter at $65.44 per ton, including shipments to Merom, $63.27 per ton -- I'm sorry, excluding sales to Merom. While some of those higher-priced shipments will tail off through the remainder of the year, we expect that the average price will remain above $55 per ton. At the same time, coal costs were over $41 per ton, which we attribute mostly to inflationary pressures. Notwithstanding the increased costs or second quarter margins before eliminations of Merom sales of $23.92 were an improvement of $6.85 over the first quarter of 2023. Comparing operating revenues from coal operations to the second quarter of 2022 highlights the impact of these high-priced contracts. We saw operating revenues from coal operations increased 73% over the same quarter in 2022, due largely to the increase in the average sales price for coal.

Operating revenues in Q2 2023 include $23.6 million sold to Merom that was eliminated in consolidation. Our healthy coal production during the second quarter allowed us to grow coal inventories by $9-.3 million. This growth provided us with the flexibility to ship -- excuse me, it provides us with the flexibility to ship additional coal to Merom if the market so dictates and ultimately will allow us the option of generating more megawatt hours in the second half of the year than previously planned.

This flexibility is especially important as Hallador Power completed its obligation of selling 100% of the output to Merom's original owner. Even with some of the initial limitations on where and to whom we could sell our output, Hallador Power contributed $9.2 million in net income during the second quarter. Starting in June of '23, as some of these contractual limitations expire, approximately 80% of our potential output from the plant became available to sell to the open market. As our operations at Hallador Power continue to develop, we are excited for the meaningful contributions that we expect Hallador power to make in the second half of the year and beyond.

On August 2, we successfully closed the new $140 million credit facility led by PNC Bank. The facility consists of a $65 million term loan with a maturity of March 2026 and a $75 million revolver with a maturity of July of 2026. As stated before, as of June 30, our liquidity improved to $56.9 million. This new facility is important for multiple reasons, including providing us with additional flexibility to make forward power sales and to react quickly to market opportunities.

We are encouraged by the general outlook on future power pricing and our increased liquidity places us in a better position to potentially lock in future profits. As I said at the start of my comments, I'm incredibly pleased with the quarterly results and the progress that Hallador continues to make as a company.

With that, I'll open up the line to -- for any questions that anyone may have.

(Operator Instructions) The first question comes from the line of Lucas Pipes with B. Riley.

My first question is on coal pricing. You have about 3 -- back of the envelope, 3.6 million tons unpriced for 2024. So I wonder what the mechanism might be for pricing those tons and where you see the market today.

Well, a large percentage of that business is tons that are committed to ourselves at the Merom power plant that we have yet to price. And so we will look at the market indicators and basically set those prices so that it's a fair transaction for both Sunrise and the Merom power plant. And there's rules around that that a market monitor will review. So I mean, that's kind of how we do that. So if you look at the general pricing curve, it will be something in that range.

And can you remind me how many tons are likely to go to Merom in 2024 out of your own production?

We figure about 3 million tons.

So essentially, the committed but unpriced portion of your book, should I think of that going to Merom?

Yes, 3 million of the 3.6 million is what's committed and going to -- well, 3 million of the 3.6 is what's going to Merom.

So we really just have like 600,000 tons that are uncommitted unpriced that you have to find a home for?

Yes.

That's helpful. And then 2 quick questions on the contract liability. As part of the consideration, I think you marked it to $184.5 million as a PPA. Based on where power prices are today, could you give us a sense where that liability would stand? And then somewhat related, the amortization of the contract liability of $19.6 million during the quarter, would that be within -- captured within your operating expenses on the income statement or where would -- how would that flow through?

So, Lucas, the contract liability runs through revenue. So it decreases revenue. And if you look at Note 15, part of the corporate and other eliminations of $23 million for the quarter, the lion's share of that decreases revenue -- increases revenue. And then the $23 million the intercompany sale. So Sunrise sold coal to the power plant and the power plant did not burn that yet. So that's part of that elimination.

Maybe we can follow up on that offline. But yes, that's -- Okay. Yes, I -- yes, what got me on this question is just when I look through the reconciliation of revenue, that's Page 22 on the 10-Q, where it shows the capacity revenue, the delivered energy PPA revenue, net asset to the $71 million that you also show in the income statement. And then there's the amortization of the contract liability of $19.6 million. To kind of back into, I guess, what would be a…

True sales.

Exactly, exactly. I'm just trying to figure out…

So, the $19 million is in revenue for the purchase contract liability that we got. So right here, we're just backing out that $19.5 million out of revenue to show you what a normalized revenue will be after that is amortized.

Yes. So essentially, the $71 million…

So, the $71 million is GAAP accounting, which includes the purchase price and then the $51 million would be normalized revenue if we had no purchase price adjustment.

Got it. And…

So the $51 million is sold power, capacity in power.

But just to be clear here, the -- and again, maybe we can follow up on this offline. But your -- essentially, the $71 million is a more market-based figure. Is that right?

More market-based back in October.

Yes. I mean, one of the issues here is when you negotiate a transaction such as this, it takes a lot of time, right? And so the price -- the seller would say, "Well, hey, look, I've got the coal purchase to generate my electrons through May of '23, right? Because that was when they intended to close the plant. And so they're saying, well look, I'll enter in an agreement with you where we sell you coal at a certain price, and by electrons at a certain price. And then when we get to the closing of the transaction, which was probably quite some time later, we have…

February to October.

February to October, we have to mark that to market, right? And there was a lot of volatility in the market last year. So that's essentially what happened. And now we're accounting for that mark-to-market.

So, yes. I mean, so in February, we were close to market. By the time we closed in October, the market had taken off as everybody knows. So we had to mark those contracts to market at the time. So Lucas, you're right in saying that the $71 million is market, but it was market in October, not necessarily market today.

Got it. Okay. So really what -- so this is all helpful. So I guess what I'm trying to get at is market today, where would you put it both on the dollars per megawatt hour and then the capacity revenue?

Well, that's not something that we disclose because we always have ongoing trading as far as selling the capacity and selling of energy. But there are certainly market curves out there that you can look at for. Indiana Hub, we actually sell to the Merom Hub, but as a more public market of the Indiana Hub, I think that can give you a feel for what electrons are selling for at various periods of time. Capacity is a little tougher. The capacity market auction is the most visible mark-to-market, but we have found that those pricings have been all over the place. And so to us, the market -- MISO capacity auction prices have really not been very correlated to the actual price that capacity is trading at. I think we've said in past quarters that we feel that we are able to sell capacity at prices that relatively cover our fixed costs. Most of our capacities have been sold through bilateral agreements with various utilities and trading companies, and very little volume for us is actually sold through the MISO auction.

And Lucas, I'd like to also point out here, you asked about the $19.5 million. We also, in the same transaction with Hoosier, we also sent -- we sold power under market in October. We also got a coal contract way under market in October as well. So that is what the $12.9 million is on Page 22 for the amortization of the contract asset. So they kind of -- they all said a little bit, we sold power. Less than market in October because of -- because we started in February. We also got a coal contract less than market -- that we had to pay less the market for.

That's kind of what -- that's kind of what this table on Page 22 is trying to add even more clarity to is, hey, here's how many megawatt hours we sold. Here was our capacity revenue. Here was the price we got per megawatt hour, and it was our cost per megawatt hour. And we've mentioned here on the call what our net income was for the plant. So we're trying to add more clarity there. We realized the GAAP accounting around the purchase asset and liabilities can make it a little challenging to follow.

Yes. No, this is helpful. Best of luck to the entire Hallador team.

(Operator Instructions) The next question comes from the line of Kevin Tracey with Oberon Asset Management.

Brent, so I appreciate this Page 22, all the disclosures you've added here. I'm going to ask you for another one. So I think what most investors are keen to know is kind of what the nonfuel cost of the power business is. There's obviously a lot going through kind of the fuel expense line with this amortization of the coal contract asset and these intercompany sales from Hallador and so on. Do you have the kind of fuel expense in the quarter and year? Would you be willing to disclose that?

Well, that's not something that we've prepared to disclose today, but we'll certainly take that into consideration for future quarters.

Yes, that would be great. Maybe I could ask it in a different way. The variable expense that you've disclosed, I think it came in at roughly $11 -- or sorry, sorry, $30 per megawatt hour. Do you have a sense of what kind of the nonfuel variable cost per megawatt hour should be on an ongoing basis?

Well, we've disclosed in the past that our capacity covers that cost, our capacity revenue. I think that's all we're willing to do this quarter.

And just to be clear, the capacity revenue covers the fixed cost, right, not the variable costs? Are you talking about capacity revenue cover in kind of all of your nonfuel…

No, it covers. No, you're correct, fixed cost. We've stated that in the last 3 quarters that our capacity revenue covers fixed costs. So, you're asking me -- are you asking about nonfuel variable costs? Is that what you're asking about?

Yes. That's what I'm at. Yes.

I mean, it is in the variable cost and it is -- I mean, the lion share of our variable cost is fuel.

And then can you talk about what the inventory position looks like at Merom? I mean, you talked about hopefully being able to generate more electrons in the second half of the year than maybe you envisioned at the beginning of the year. Where does inventory stand at Merom? And then I think you have 4 million tons of kind of contracted price tons to sell to third parties in the second half. Is there a chance that your customers might be willing to defer some deliveries outside of this year and that might unlock more inventory to burn at Merom?

Well, I mean, as far as what our customers are willing to do that kind of changes on a daily basis. But yes, I mean, I think what we said in the call is and what we've said in prior calls is the power -- or coal prices last year took off. We sold a large percentage of our coal to third parties. And now because our production has been, well, has exceeded sales, we are generating inventory in the first half of the year that we think that we'll be able to burn profitably in the second half of the year. That's going to be dictated by the price of power, right? I mean we -- these are not contracted forward power sales for the most part.

So the benefit and the burden of having our power book, 20% contracted, 80% open market for the balance of the year is -- we think we can achieve higher prices than what were previously contracted for in the first half of the year, but that will be up to the market, right? I mean, some of that is weather dependent. Some of that is gas price dependent. Power prices change every day. All we're saying really is we have more fuel.

And because of that, we'll be looking to burn and generate more megawatt hours in the back half of the year was maybe another way of saying is there's potential depending on power prices for the power plant to make more money in the second half of the year than in the first half of the year, but that is wholly dependent upon what we see in the market as far as the price of power. We just have the inventory to do it should the market show us values that makes sense.

So would you say the power plant is not inventory constraints or to the extent the power prices are favorable in the second half of the year, could you run the plant at a high-capacity factor or is there a point where you might run out of inventory?

No, we feel we could run at a high capacity factor if the market showed us the appropriate pricing.

And then on the cash flow, so the free cash flow conversion hasn't been great in the first half of the year. But now that you've completed your coal purchase contract acquired with Merom, is it fair to say that you're going to burn down a lot of that coal inventory in the second half and free cash flow should be quite robust in the second half? And I didn't hear you say, I think the prior goal was to hopefully be net debt 0 sometime early next year. Is that something that you reiterate?

Second quarter, yes, we think we'll be net debt free. And to answer your question on the inventory, yes, we plan on drawing inventory down as much as possible at the end of the year. I think we had like $9.4 million increase in inventory, which, as you point out, decreased our cash flow, we expect that to turn around and then some because we will draw our inventories down. It's dependent upon power prices, depending on customers show up, but our plan is to draw inventory down to a very low inventory balance at the end of the year.

Depending on power prices.

Solely dependent on power prices. We have the coal sold to a third party. So they're obligated to come and get it, whether they -- I mean, there'll be something there if they don't come and get it. I mean, it will be a carryover to be some kind of settlement. But -- and then power prices.

And lastly, on the coal cost per ton is kind of low $40s, a good expectation going forward?

We think we can get those lower. 2 years ago, we were at $32. I don't know if we'll ever get back there with inflation, but we are working on things at the mine to help geology, to help mining conditions and more efficiency, we think we can get them down from $41, but I'm not going to throw a number out there. But we are working on lowering them and think we can.

(Operator Instructions) We have a follow-up question from the line of Lucas Pipes with B. Riley.

Just looking at the megawatt hours sold in the first quarter and the second quarter 2023, we had that drop from $1,262 to $1,043. Is that just seasonal and kind of looking ahead at what level do you look to run the plan going forward?

Well, again, that's somewhat power price dependent, Lucas. In the first quarter, 100% of the output was committed to the seller of the plant. And that essentially was the pace that they wanted us to run at. In the second quarter, 2 of the 3 months were in the same -- managed the same way. So really, June was the first time that we were in a position to sell the majority of our electronics to market and that kind of dictated the pace of the plant. So -- but you're also in the shoulder month right there, right? I mean, you've got…

April. You had 2 shoulder months in the second quarter and only 1 -- I mean, March really isn't (inaudible) month.

Correct. And April wasn't very hot. So you typically expect your plant to run more in July, August, September, those are hotter months than April, May, June. And we'll see what winter brings. Does winter show up in November, dose winter show up in December, or does it show up in January? So, the power business is a much more seasonal business, particularly when we have more market exposure versus what we're seeing -- what we've typically experienced in just the coal business, right? Typically, the coal business, you've got it under contract, and it really just kind of comes down to, well, payout visibility on the sales, what it might cost of production and what volume are going to be at. Said another way, I think that longer term, you'll see the plant probably run more at 1.5 million megawatt hours per quarter. Those will be probably a little more aggressive in the heating and cooling season and a little lighter in the solar season from a volume perspective. That's where we'd like to be.

And in June, was the utilization rate higher or lower than in April and May?

Prices were pretty soft in June. It was pretty mild here in the Midwest. Quite frankly, we haven't -- heat showed up basically in the first 3 weeks of July. So July was pretty good. I think it's been relatively mild here the first week of August, but we'll still see what the summer brings. And gas prices affect this too. That said, I think long term, I think the margin potential of the power business is very good. And so I think -- we haven't really had -- you'll look to see us price a little bit more of our power going forward. And hopefully, next quarter, we can be in a position to disclose more of that. And I think the market will be pleased with the pricing that we're seeing, but that -- we'll talk about those deals when they're signed and we can report it.

That's helpful. Then back to Page 22. You net out the amortization. You show that average price per megawatt hour delivered energy LTPA revenue of $32.89 per megawatt hour, and you show that cost on a variable basis of $30.05. Are those 2 metrics may be the best to kind of where the market is today to model this business going forward?

I don't think on the sales side, that is not market today. I think on the cost side, yes, you're starting to see a couple of quarters here of where our costs are at or the plant, and that's both fuel and variable costs.

Because realized like second quarter, Lucas, as Brent said, is a shoulder month, so it's lower prices to begin with, and it was quite cool in April, May, and June wasn't that great either, so.

So kind of what the cost (inaudible).

When I say cool, not cold.

Yes, that's clear. So in other words, the kind of at current market prices, the average price per megawatt hour delivered energy and the PPA revenue would be somewhat higher?

Significantly, yes. I mean, again, Lucas, it kind of gets into what time period are we talking about, right? I mean if we're talking about spot power tomorrow, if the temperature is mild and gas prices are cheap, it's not going to be a very good price. If we're looking further out on the curve, I think we're pretty excited about what we see out there. So it's -- I just don't want to -- first of all, we have ongoing negotiations, so I don't want to tip our hand. But also I don't want to confuse the market either because pricing today is potentially very different than pricing 2 years from now.

(Operator Instructions) There are no additional questions left at this time. I will pass it back to Brent for any closing remarks.

I want to thank everybody for their interest in Hallador and joining our call today, and we look forward to reporting more great results to you all in the future. Thank you.

That concludes today's conference call. Thank you. You may now disconnect your lines.