Hallador Energy Company (NASDAQ:HNRG) Q3 2023 Earnings Call Transcript

Hallador Energy Company (NASDAQ:HNRG) Q3 2023 Earnings Call Transcript November 7, 2023

Operator: Hello, everyone, and welcome to the Hallador Energy Third Quarter 2023 Earnings Call. My name is Emily, and I will be coordinating your call today. [Operator Instructions] I will now turn the call over to our host, Rebecca Palumbo. Please go ahead.

Rebecca Palumbo: Thank you, Emily, and thank you, everybody, for joining us today. Yesterday afternoon, we released our third quarter 2023 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 up the call to your questions. 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 one 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. For a discussion of those risks and uncertainties that may affect our future results, please 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, we will have an archived webcast of this earnings call on our website. We encourage you to ask questions during the Q&A, and if you are on the webcast and would like to ask a question, you will need to dial in to the conference line.

That toll-free number is 1833-470-1428, access code 224373. And with that, I will turn the call over to Larry.

Lawrence Martin: 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 $16.1 million, which was $0.49 a basic earnings per share or $0.44 per diluted earnings per share. For the year, net income was $55 million, $1.66 earnings per share, $1.52 diluted earnings per share. We had adjusted EBITDA for the quarter of $35.9 million and, for the year, $105.2 million. We decreased bank debt by $12.5 million for the quarter, $23.5 million for the year.

Our funded bank debt as of September 30 was $61.8 million. We had letters of credit totaling $11.2 million. And our net funded bank debt was $59.2 million, 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 seven point – 0.71 times for the quarter. I will now turn the call over to Brent to review the quarter and beyond.

Brent Bilsland: Thank you, Larry. First, I would like to thank the Hallador team for their hard work and dedication on creating another successful quarter. As I have 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 of $16.1 million for the quarter helped build on our record net income of $55 million for the first nine-months. And our continued record operating cash flow of $79.5 million over the nine-month period has allowed us to invest $48.7 million in capital expenditures to improve our efficiency and reliability at both our mines and our power plant.

We made continued progress on our goal of improving our balance sheet by repaying $23.5 million of debt during the first nine-months of the year, $12.5 million of which was during the third quarter. This further reduced our leverage, as Larry said, to 0.71 times, while we increased liquidity to $66.4 million as of September 30. On October 2, we successfully amended our credit facility with PNC 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 third quarter, high coal sales prices, coupled with large coal shipment volumes, led to record coal revenue. 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 third quarter and into October to better – to obtain better geologic conditions. This led to higher cost and decreased production during this time frame, but is resulting in overall production improvements following the moves, which we expect to continue. During the quarter, we shipped 2.1 million tons of coal at an average price of $56.43 before intercompany eliminations. We produced 1.6 million tons in the quarter at $46.54 per ton before eliminations. Leading to margins of $18.89 per ton during the third quarter before eliminations. We expect an average price of $54.30 per ton 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, increased 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 eliminations.

We set the price of coal we sell to ourselves based on third-party market indicators that we review from time to time. Cost per megawatt hour were $23.49 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 1.3 million megawatt hours. 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 million 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 million of capacity and revenue over the years 2024, 2025 and 2026, bringing this number of total sales up to $366 million.

These sales are important as they create a profitable foundation for our Power division over the next five-years, with sufficient energy sales at – or excuse me, with significant energy sales at $56 per megawatt hour, and capacity prices approaching $220 per megawatt day. Now we get a lot of questions concerning how an investor should think about Hallador now that we have added a power division. To add clarity, we included a detailed section – we included a lot of detail on Section 3 of the overview of the MD&A outlining our sales of coal, power and capacity through 2028. At a high level, I think about our business as such. We produce seven million tons of coal annually. Just over four million tons is sold to outside customers and almost three million tons is sold to our Power division, Hallador Power.

The reference table will show that, over the next five-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 ton. Our year-to-date cost per ton to produce coal was $43.25. The other three million tons assume that we will annually produce 6 million-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 the internal eliminations. 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 third quarter, our consolidated variable costs at the plant was $23.49 per megawatt hour. As stated in previous quarters, we use our capacity sales to cover the majority of our fixed costs at the plant. We have sold and we expect, with the capacity prices that we are seeing, that to continue. We have sold approximately 27% of our future power through 2025 at $34 per megawatt hour, roughly a $10 margin based upon that cost structure. But in this past quarter, we have sold 3.3 million megawatt hours for the 2026, 2027, 2028 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 two when we had an unplanned transformer outage in one of the generators at the power plant.

The transformer has since been replaced, and the event will cause us to miss a net two to three weeks of output from one of those two units. I want to reemphasize, I am 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 a 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.

Lawrence Martin: Before we go to questions, I want to clarify one sentence here. Our shipments were 2.1 million at $65.43 for the quarter, for an $18.89 per tonne margin.

Brent Bilsland: Thank you, Larry.

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Q&A Session

Operator: [Operator Instructions] Our first question today comes from the line of Kevin Tracey with Oberon Asset Management.

Kevin Tracey: Great. The first one is just to clarify what I thought you just heard you say about the outage at Merom. So in the 10-Q, there is a note where it says the unit isn’t expected to be back into service for the second half of December. But I thought I heard you say that the outage was only two to three weeks. So I guess, was it – are we kind of missing 2.5 months or two to three weeks of this unit?

Brent Bilsland: Yes. Let me clarify that. So the unit was already scheduled to get on a scheduled outage from November 1 to December 27. That is something that we schedule with MISO six to nine-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 is December 27, it will probably come back online a week or two earlier than it was previously scheduled. So net-net, we are going to lose this unit – one of the two units for two to three weeks longer than was expected and planned for.

Lawrence Martin: Cross your fingers the power prices are higher in December.

Kevin Tracey: Okay. And going forward, will there be – do you expect any impact on MISO’s accreditation of the plan for purposes of future capacity revenues or are you hoping that won’t be material?

Brent Bilsland: Yes. I think every time you have a forced outage – so accreditation is a rolling three-months – a three-year process, right and so they are looking at your performance history during that time frame. 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. And we are spending additional monies this year and next to kind of get the plant back in what I would call tiptop shape. And so where that helps you on accreditation is we are seeing higher output numbers than 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 are able to achieve higher performance.

That is to the good side. The bad side is, every time you have an unscheduled outage such as we had with the transformer, that counts against you in accreditation. And then I would say, thirdly, we still see MISO making tweaks and adjustments to their accreditation process. They have 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 is always hard to say. So all we can do, and what we have done is, as of our last accreditation, which was eight hundred and – I mean it is on a seasonal basis, but I think on average, our accreditation was 860 megawatts. That is what we are basing our numbers on. So when we show you, hey, here is how much capacity we have sold as a percentage of the plant, it is based on an assumption that our accreditation is 860.

But that number could go up or down based on our accreditation from MISO.

Lawrence Martin: And I want to emphasize on one thing Brent talked about. 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 even 20 degrees or something like that in the winter when there is a lot of demand for electricity. So us being down in October in a mild season may not count as much against us as – and we may get more upside when we come back on in December. That is total speculation, but it is…

Brent Bilsland: Odds are we are going to have colder weather in December than we had in October. Power prices theoretically would be higher. So it may not be as – we may be trading 4 mild weather weeks for 2 cold weather weeks. We just don’t know and we won’t know until we get there.

Kevin Tracey: Understood. Okay. And then, so with these power sales agreements you have entered in. So you have sold about one fourth 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 power forward as a percentage of your expectation? And then how are you managing the risks there, or if the plant were to have an unplanned outage and you have agreed to supply power at certain prices, if you find yourself long the power market? So how are you kind of managing risks when you are thinking about entering those agreements? And if you could touch on how high you are hoping to go in terms of forward sales.

Brent Bilsland: Yes, good question. So far to date, everything that we have sold on the power side is plant or unit contingent, meaning that we sold the power, and if we fail to perform, 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 it or they have to go buy them elsewhere. But that is not on our accounts. So I think as excited as we are about our sales, on a risk-adjusted basis, we are extremely excited about that. I’m going to look to see what opportunities are for – these are bilateral agreements. These are not exchange hedges. On an exchange hedge, as 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. And so part of our process and what we have 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 will look to the market to see if there is hedges that we want to – additional hedges that we’d like to layer in.

Kevin Tracey: Okay. And then on the mining cost per – sorry, go ahead.

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

Kevin Tracey: Got it. Okay. And then on the mining cost per ton, I think heading into this year, the hope was that we would see an improvement over 2022’s $37 per ton. We have obviously seen costs rise quite a bit from there. Can you talk about sort of what went wrong versus your expectations? Was it just and general inflation or an issue with the geology? And you made some comments about improvements you are seeing from some changes you are making. Can you help set expectations on where you think your mining cost per ton will be for 2024?

Brent Bilsland: So on the production outlook, it is pretty – we have seven units – seven individual production units underground. I think it is pretty typical in any given quarter for one or two of those to be struggling. What was unusual about this quarter is we had four units struggling. And we – sometimes that catches you at a time that is a little out of sequence to be moving. So 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. And there is just lost time in production when you do that, particularly out of sequence like we did this quarter and into October. So, very unusual to move four units at any given quarter, but that is what we did.

And that is ultimately had an outsized factor on why our costs were the highest they have ever been in any quarter in the history of the company. So, disappointed by that. All I can say is we have 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.

Kevin Tracey: 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?

Brent Bilsland: I think that I think we will – we have seen inflation. So I think probably in 2024 – gosh, some of that is going to depend on what the production levels are at each mine. But I think you will see us back into the low 40s, upper 30s.

Kevin Tracey: Okay. And then on the CapEx, so your fourth quarter guidance implies that the full year CapEx will come in about $10 million than your original budget. And it looks like all of that, I guess, 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 affluent project at Merom and kind of where you are thinking the CapEx budget is going to look like next year?