Hallador Energy Company (HNRG) Q4 2020 Earnings Report, Transcript and Summary

Good day. And welcome to the Hallador Energy Company Fourth Quarter and Full Year 2020 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions]. After today’s presentation, there will be an opportunity to ask questions. [Operator Instructions]. Please note, this event is being recorded. I would now like to turn the conference over to Becky Palumbo. Please go ahead.

Thank you, Tom. Good afternoon, everyone. Thanks for joining us today. Early this morning, Hallador Energy released its fourth quarter 2020 financial and operating results on Form 10-K and issued a press release containing certain financial metrics. Both documents are posted on our website. Today, we will discuss these results as well as our perspective on market conditions and outlook. Following our prepared remarks, we will open up the call to your questions. But before beginning, a reminder that some of our remarks today may include forward-looking statements that are subject to a variety of risks, uncertainties and assumptions contained in our filings from time to time with the Securities and Exchange Commission. While these forward-looking statements are based on information currently available test, if 1 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. In providing these remarks, we have no obligation to publicly update or revise any forward-looking statements whether as a result of new information, forward future information or otherwise unless required by law to do so. With us on the call is Brent Bilsland, our President and CEO; Larry Martin, our CFO. And with the required preliminary out of the way, I'll now turn the call over to Larry Martin.

Good afternoon, everyone. Before I get started with our review of our operating results, I would like to go over a couple of definitions. We define free cash flow as net income plus deferred income taxes, depreciation, depletion and amortization, ARO accretion change in fair value of hedges and stock compensation, less maintenance CapEx and the effects of our equity-method investments. We define adjusted EBITDA as earnings before interest, taxes, depreciation and amortization, plus stock compensation, ARO accretion and changes in fair value of hedges less effects of our equity method investments in Hourglass Sands. Hallador Energy incurred a net loss of $4.7 million for the quarter or $0.15 a share, a loss of $6.2 million for the year, which equates to $0.20 a share. Our free cash flow for the quarter was $2.9 million, for the year $27.6 million. Our adjusted EBITDA was $9.4 million for the quarter, and $53.5 million for the year. We had a decrease of our bank debt of $9.2 million for the quarter and $42.4 million for the year. We paid dividends of zero in the quarter and $1.2 million or $0.04 a share for the year of 2020. Our bank debt at 12/31/2020 was $137.7 million of borrowed funds and $5.7 million of letters of credit. Our net debt as of 12/31/20 was $129.7 million. And our debt-to-EBITDA leverage ratio was 2.68 times. I'll now turn the call over to our CEO, Brent Bilsland, for his summary of the quarter and the year.

Hello. Thank you for joining. The global pandemic brought huge disruptions to the energy markets as people stay home and sheltered in place. Oil prices went negative for the first time. Natural gas prices dropped to multi-decade lows and coal plants struggled to dispatch for at least 2 months in early 2020. Despite these challenges, Hallador displayed great resiliency as evidenced by generating strong operating cash flow of $52.6 million. Hallador has continued its focus on debt reduction as we paid down $42.4 million of bank debt, representing 24% of our outstanding bank debt. We maintained $51.8 million in liquidity, even as our EBITDA -- debt-to-EBITDA ratio rose slightly to 2.68 times. On April 16, you may remember, 2020 Hallador received a $10 million loan under the Paycheck Protection Program. And we expect the loan to be forgiven by April 8 this year. As our customers' inventory levels grew at record highs in 2020, we worked with them to modify shipping schedules, sell additional tons and extend the terms of our contracts with multiple customers. Shipments for the quarter were 1.6 million tons. Coal inventories were reduced year-over-year by $2.8 million. Our operations team is also raised to the challenge implementing new safety protocols and training to protect the health and safety of our employees. Out of an abundance of caution, at times up to 25% of our workforce was quarantine due to possible exposure issues. These operational hurdles, coupled with some temporary poor recovery in the fourth quarter led to slight cost increases of $31.07 in 2020 versus $30.69 in 2019. And Oaktown, costs were $29.84 versus the year before $28.35 million. As our recovery has now returned to normal and as increasingly more of the population receives vaccines, plus disruptions from COVID-related workforce issues, we anticipate our costs returning to the lower end of $29 to $30 in 2021. Looking forward, energy markets are recovering as evidenced by the forward strip on natural gas price is up 44% year-over-year. As of the end of January '21, Illinois Basin utility inventory levels have returned to 48 days of full load burn versus being in the low 60s in May of 2020. Inventory levels are expected to drop further in February as a result of the cold snap that affected most of the nation. This return to normal was further displayed by Duke Energy and [Southern] company services to the largest utilities in the nation, coming out for request for proposals to buy coal over the last few weeks. Though Texas received the majority of the nation's attention over the 4-day long blackout, MISO, which operates the grid in the Midwest experienced the same cold weather that felt much better as coal represented nearly 60% of its power supply during the cold snap. The Texas event has caused many decision makers to question our nation’s pace. The transition to carbon-free electricity. One call I saw last week of roughly 2,000 voters, conducted by Council founded 7% and 10% registered voters support maintaining baseload on-demand power plants such as coal plant to support the reliable supply of electricity. In the last 7 months, California and Texas, the 2 states with the highest concentration of renewal generation at 30% have both experienced multiple rolling blackouts. We acknowledge greening in the grid, but believe that coal will play an important role and supported the grid for many decades to come. With that, I will open up the microphone to -- I'm sorry, 7 out of 10, I misread my document here. 7 out of 10 support maintaining baseload on-demand power plants. Sorry, I miss quote. With that, I'll open up the microphone to questions.

[Operator Instructions] And the first question comes from Lucas Pipes with B. Riley Securities.

Brent and team, good job on navigating this is very difficult to past year. I wanted to follow-up on the comments you just made there regarding kind of the storm and then also the renewed purchasing activity. And kind of what's your outlook for coal burn this year, specifically kind of on a year-on-year basis? How sustainable do you think it is kind of as we look at 2022 is going to be a continued erosion, given the plant retirements kind of at the stage where we are today, kind of what's your outlook for cold burn, this year, next year? And maybe just to horn in a little bit further. Any particular comments on Illinois Basin would be appreciated.

Sure. Thank you. I would say what we saw last year was if you look at that, mid-March to mid-may time frame, coal point is really the dispatch. I mean natural gas price is down around $1.50 per as people stay at home. And so what we saw is co inventory levels at our customers grew dramatically higher, especially towards the end of May, mid-June. And then basically, inventory levels have been declining from that peak everyday sense. And we're we were happy with what we kind of saw data wise at the end of January. We haven't seen the end of February coal inventory levels yet as have yet to be reported. But we know just with the record amount of cold weather everywhere, those inventory levels got drew down further. And when it's that cold, either trucks or rail perform that well from a shipment perspective. So we think that the market has improved. I'm not -- I sit here and say it's great yet, but it certainly must improve from where we sat 6 months ago. We've seen the other coal companies came out and say that they have booked, that export shift in coal. I don't think anybody expected to ship exports this year. The LNG pricing got so terribly high in December. And I think marker got up to $32 an MMBtu, which is a record. And so coal is exporting for various reasons. So that's helped to get some of that inventory level out of the area. We've seen some supply come offline, both from us and from competitors as well. Some of that actually a fair amount in Indiana that looks to be permanent. And so I think the utilities have been long and wrong for quite some time. And so now they're kind of playing a wait-and-see approach, but we think they have to buy coal at the end of this year. They're probably going to try to get this summer and just see how strong the summer burns are so they really come in and buy big volume with the spot purchases here and there. We think strong -- we think our sales are strong, considerably stronger in 2022 than they will be in 2021. Just from what our customers are telling us what their open position is and from mine closures, that typically supply market that are no longer operating. So from that perspective, we see our coal sales being stronger in '22 and '21.

That's very helpful. And then another topic I wanted to touch on is M&A. And historically, you've had some opinions on M&A and the industrial logic behind it. Do you see increased appetite today from my vantage point, it's been pretty quiet, but would be curious to see if maybe something changed on the ground?

Yes. I think that you will see continued M&A efforts. If the market gets smaller, we think you'll see more consolidation. And that kind of kind of the reason behind that is, we're seeing contracts getting moved from high-cost production to low-cost production, just seeing the higher cost mines come off-line. And the lower cost mines produce more. And I think that's just the natural progression, especially as we see power plant closures over the next decade or 2. So yes, I think we see it. Capital for fossil fuels is certainly more challenging than in years past, but it is available. And we'll see what the market brings.

Okay, that's helpful. And Brent, I'll ask a final one before I turn it over. In terms of the outlook on natural gas, I'd say you've always been able to look a little bit beyond the corner in terms of what's coming your way in terms of the price on the computing fuel there. What's your analysis today, say, about natural gas prices, obviously a huge impact for the competitiveness of coal in the Illinois Basin in particular?

Yes. I think capital for oil and gas became more expensive mid-2019. And then 2020 certainly brought challenges for everyone in the energy space. And so that kind of force a little more capital discipline into the oil and gas producers. And I think that a lot of guys have -- on one hand, we still see productivity gains from some of those producers. On the other hand, we're starting to see some of the Marcellus and Utica become pipeline constrained. And so it's going to be interesting to see if future pipelines can be built. I think there's -- the non-power pipeline, I think it's got a shot at getting built. What we had to rise bought Atlantic sales pipeline will get built, and it doesn't look like that's going to be the case now. So if you really kind of pay attention to the gas, yes, there's a lot of low-cost gas, but there's very few basins anymore, in my opinion, that have access takeaway capacity. Really good job of building pipelines to get gas out of the U.S. and the Mexico and building LNG export facilities to get gas out of the country and in Europe and in Asia. Those facilities were running wide open in the last few months. That's been somewhat of a release out to get that gas out there. And that's kind of what we're seeing is gas prices are up 44% year-over-year. That means coal plants are going to burn more, right? I mean they're going to dispatch at a higher percentage, the higher the price of gas is. And from a liability perspective, it's going to be interesting to see. Like I said, back in August, California had multiple rolling blackouts and their renewable profile is a little bit over 30%. We saw California year had several natural gas plants that were slated for retirement. But as they've had reliability issues, now they push those retirement data out. And we think a similar narrative can be made for coal is that, yes, certainly, there's a lot of pressure and a lot of desire by environmentalist and those more on the left side of the policies. But at the end of the day, no one's willing to sit in dark. We've seen this in California, we're seeing this now in Texas. And we're seeing any leader who lets us sit in the dark quickly losses their leadership position. And so I think that's -- what we're seeing is legislators from across the country that are pulling these ISO operators, MISO in the Midwest, PJM, SPP and others and say, "Hey, explain to us how this can never happen in our region," right? And so it really kind of comes back to diversity of supply. I mean if you look at Texas, Texas got a lot of gas generation. But it couldn't get gas from plants. And use that in that case right there, we saw in Indiana, where a coal-fired power plant was running full bore all through the night. And the gas plant was on by the same utility wasn't running because the local price of gas was $500 of MMbtu. So they were dispatching. They are offering that plan -- a gas plant. It was available, but it was being offered in at $3,600 a megawatt hour. A megawatt hour typically sells to $25. And so public certainly said, wait a minute, how is it possible? How can we basically have our power interrupted 4 days at a time, in Texas, and then you take this is a $6,000 power bill, right? And so because of that area, I think a lot of people are looking at that and saying, well, wait a minute, it turns out there is a big difference between baseload power and interruptible power, right? Renewable power doesn't have an off switch. It comes on when the sun shines and the wind blows, or you have to back it up a battery set into the batteries. In most of these markets, they're only backing it up for 4 hours. So what happens when you have an event that last 4 days. So from that perspective, it seems to be a challenge for any market to go over 30% renewal. I'm not saying it doesn't happen, I am just saying that really seems to be the law of resistance. And we hear that from MISO in Indiana is that, "Hey, we're at 10% renewables. We think we can get to 30%" and then, "Boy, it really is difficult." It's going to take a lot of transmission lines that get built, and transmission lines typically take decades, not years. I think the Biden administration is working on this. They are looking at this saying, well, how can we speed this process up? But there's just a lot of steps, and quite frankly, now in on the powerline build in their backyard. So there's lots of ways for the public to fight that. So all of this is another way of saying that we acknowledge this greening of the grid. We just think this transition is probably going to take considerably longer than what politician and the press would have you believe.

[Operator Instructions] The next question comes from Douglas Dethy with D.C. Capital Partners.

Thank you for the good results in 2020. Lots of challenges, for sure. But good results as far as I was concerned. Could you talk a little bit about your -- given the uncertain environment, but maybe with a little bit of an upward bias the ability to, I guess, flex production up? And kind of what is the marginal cost on doing that per ton?

Well, we do have the ability to flex up to 8 -- over 8 million tons. And actually, as in most manufacturing and miners, the incremental cost would be negative because our cost would be lower if we maxed out our production.

So -- I mean, your average cost would go down, you're saying, but at the margin, how much will your marginal cost be? I mean, there's always some marginal cost?

I think that's probably a number that we don't really want to disclose from a competitive point of view. I think that if you look back over the history of our company, when we run over 7 million tons, you typically see a pound average cost structure in the mid- to lower 20s.

Okay. That's helpful. And so -- yes. And do you think on the pricing on the coal going forward as -- with the natural gas strip up, as you mentioned, is the pricing on the coal going to -- is it coal on coal competition so much or coal versus natural gas, do you think, in terms of the price setting on any incremental demand?

Natural gas kind of sets the size of the market as well as the electricity demand. And then once the size of the market is kind of set, then it becomes more coal on coal competition.

And that's -- we have 1 customer in particular that tells us "Hey, our model shows that our dispatch could be anywhere from 7 million tons to 13 million tons in a given year." And so typically, what they'll do is try to buy towards their minimal burn and then fill in the balance with spot sales or even potentially longer-term sales once that burn forecast really starts to materialize. And that's -- we kind of think this year is one of those years, where the utilities are bought at the minimum levels. And it's been caught long and wrong before, especially last year, nobody really saw the pan in income. And so we think that they do have open positions in the back of the year, and that's we're expecting to participate in that. We know there's significant open positions with our customers starting in '22. Gas market we'll continue to kind of set the size of what that market opportunity is.

No. That is certainly helpful. You mentioned the customer survey, and if I understood it correctly that people are obviously very upset about the lack of stability and supply of electricity in different parts of the country. And do you have an idea from your customers, the people who make the decisions tend to be the right commissioners. And often influenced by the political figures. Is that -- do you think it's going to reach that level? Or it has -- you sort of implied that it had already reached that level? Could you talk a little bit about that among the decision makers as opposed to the broad population on the sort of the Texas fiasco, if you will?

So Texas is an unregulated market in the end of the regulated market, by and large. The decision is to build a plant because there's a gas plant, right? And we've seen proposals from customers that are, let's ship this coal plant and build a gas plant. A couple of things are happening there. First, you're seeing the you're seeing legislators all of a sudden and say, well, wait a minute, is, of course, the utility wants to build a gas plant because they get a guaranteed rate of return on the cost of capital of that plant. But from an environmental perspective, the guidance de-nitration is clearly focused on trying to get carbon emissions down. If we allow a gas plant to get billed, what if there's a rule down the road that all of a sudden, now we have a stranded out -- we have greater stranded asset risk, we're trying to build new gas-fired power plant. And so we think that this might favor coal in that or an , these plants are already built. They're already paid for already hope for them. You should use the coal finance have to transition to greener sources over time and use that to stabilize and back up the grid and revenue on shutting down coal building a new gas plant and then having a gas plant has a trended asset, 10, 15, 20 years down the road and not reaching its full 30, 35 years span of amortization. So you're starting to see discussions of on politicians, specifically in Indiana around, hey, does it make sense to shorten up the amortization schedules on new fossil fuel build such as gas. And I think that type of conversation, coal. The part where you're really not seeing any headlines because they work a little quieter is the ISOs. The ISOs now are -- MISO has come out and said, hey, they're going to reallocate the capacity factors of wind basically cut them in half of the MISO district because originally, he came out and said if you've got a gigawatt of wind, we're going to give that a 25% capacity rating in the capacity markets. So that means when a gigawatt of wind is going to be credited for 250 megawatts of capacity. Come back and said, "Hey, we're just not seeing an amount of reliability out of the wind generation assets. So we're going to reaccredit those assets here probably this year." And I think everyone is expecting that to drop to something like 12%, 13% versus 25% of capacity. So meaning a gigawatt of wind would suddenly only have 130 million -- or excuse me, 130 megawatts of capacity accreditation. We've seen discussion at MISO level and other ISOs of winter constructs and all of this is just another way of saying they're going to make sure that they build and not resources into the grid so that there's not a failure. And those ISOs that are lucky enough to have fuel diversity and are lucky enough to maybe be a little slow to the greeny process are going to have much more reliability and they're going to get to watch and see the mistakes of other ISOs that were more aggressive. And California and Texas have been to date, the most aggressive looks like to be the New York ISO is put out some mandates that are extremely aggressive. So those will be items that more conservative, ISO will probably sit back and watch and say, how would they do it? What did they get right? What did they get wrong? And what do we need to do to make sure that the lights stay on. But -- and we just saw it. We just saw it a few weeks ago in Indiana, where I would say, yes, I mean all of MISO, which is -- MISO didn't have the most customers, but it had the largest footprint. Any ISO in the country was all the way from Louisiana to the top of Alberta, Canada. And at times, that grid was floating it being 60% coal fire power. And so I think all those is operators have to say, what happens down the road if we shut those assets down, how do we handle these taxing events, which is resiliency, right? I mean that's kind of the discussion. It's kind of very interesting that the by FERC decided the week that Texas with city and the dark to cancel Trump's resiliency study. I mean, as timing is right, why we delay that decision a week, right? People are sitting at the dark and FERC is coming out and saying, we know we're responsible for reliability. But we're not going to do a resiliency study. So a lot of people all know that differ between reliability and resiliency. Reliability is like get a light switch and flip it on 100 times it comes on 99 times. Resiliency needs the house gated by lightning and then it is floated and the light switch still comes on, and we can take the look and keep on ticking. Texas proved in February did not have enough resiliency. And they'll, I'm sure, do the correct things to make sure they get that building in the future. And I think it's got as much of the country between that and what happened in California talking about how do you build more resiliency into this grid, which means probably base assets that base of assets stay on longer, whether that be coal, whether that be gas, whether that be nuclear.

No, that's really, really helpful. I appreciate it, really insightful. So just to summarize, what does that mean if looking at it in terms of, I guess, kind of death sentences that some of these coal plants could get a longer-term until they're supposed death or extinction by regulation or get commuted all together by a natural death, if you will, is not too much to read into it?

Well, I think you can look to California where they had 4 gas-fired power plants that were all slated to close this year and all those -- to my knowledge, all those plants are still in place and still operational because at the end of the day, leadership knows whether that's political will is an ISO operator whether that's present in the United States, if you let people sit in the dark, you're going to be out of job. So we all have goals and we all have targets, and those are certainly noble aspirations, but we're not trying to deny that exists. And we certainly acknowledge that it's headed in the direction. Our point is this transition is much more complex and will take more time than what a lot of people get a credit for.

The next question comes from [Bryan Bassett], who is a Private Investor.

I was wondering if I could a couple of company-specific questions. First, if you could talk about -- I think at the end of the third quarter, the contracted sales that you were expecting in Q1 was a little over $2 million, and it came in at $1.6 million. So if you could talk about that a little bit and then also talk about CapEx in '20, and what you're projecting in '21 in terms of the split between maintenance and growth CapEx and maybe a little more detail on what that growth CapEx is going into in '21? Because it looks like it was expected to be from the $13 million or $14 million?

So I'll take the first 1 on, on coal sales. And I think you said first quarter, I think I meant say fourth quarter. But yes, we were expecting $2 million for the quarter, but basically, because of the lack of demand, customers came to us and we were able to negotiate extensions to where we would push times to over years. An agreement for selling more tons and adding, in some cases, up to 3 years to the length of our contracts. So I think we reported in the -- I know in the management commentary, this 2 years of sales. So you don't really see a growth in sales in D&A section. But our total contract position pretty significantly. So some -- I know one of the contracts went as far out as 2027. I think I mentioned the sales question. I'll let Larry here answer your CapEx question.

Yes. So CapEx, the investment CapEx for 2021 of the $13 million, a little less than half of that is for a man drop elevator in Oaktown 2 that we are building to, say, basically production type travel to the face, which we think that's $5 million to $6 million, and that's less than a 2-year payback. The other gross CapEx, we are not ready to disclose at this time.

So just a little more color on the elevator. Once we start mining 5 miles out, to vision to portal, it makes sense to put an elevator and stop our people in much closer to the operating phase. And as is usually pretty -- as he said, 2 year paybacks, is usually our math because we save significant labor that people driving around, trying to get to the phase that we drop them in very close to where they're working or much more productive right away.

Okay. And I guess just a follow-up then on whatever the project is that you're not at liberty to disclose right now. Is that something that's already committed to, or is that something that you're going to wait and see how 2021 develops in terms of expecting more orders or growth in 2022?

Yes. So quite -- right now, it's a placeholder. We are in negotiation. And so if we're able to develop that. That will -- if we're able to contract, then we'll have a capital expenditure there. We think that is likely announced that we chose to put it in our budget.

[Operator Instructions] Next question comes from [Sam Serio], who is a Private Investor.

The question if you look at the contracted prices, I think that was touched on the last question. It's down a little bit from last year. I was wondering if there's a reason for that given the natural gas tailwind or if that's 2 different things that aren't really related?

Well, the contracts for '21 were -- most of them were all -- were entered into way before the natural gas prices went up. So that's the reason why they're a little lower is because when those were entered into natural gas was lower than it is today.

And then the second question was, I think, back late 2020, early 2021, there's some local news articles about storage facility down Indiana, I think, by a Duke Energy plant. I was wondering if there was any more color on that or any more news or development?

Well, we built a rail faculty down there, Princeton, Indiana, which is right next door to energy, it some patient power plant. And that really is where we truck coal to the NS railroad to hit various other markets. And then we have a lot of land there. So it is designed and permitted. To be able to store coal for customers in the event that they need that. Currently, we do not have any stores for customers at that facility. We have a little bit of coal stored at our Oaktown mine, but it's fairly insignificant.

This concludes our question-and-answer session. I would now like to turn the conference back over to Brent Bilsland for any closing remarks.

Well, I just want to thank everybody for their interest in Hallador. And we will continue to try to generate positive cash flow and pay down debt. That's the direction we've been added, and that's the direction we'll continue. And I look forward to talking to you at our next quarterly call. Thank you.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.