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. After today’s presentation, there will be an opportunity to ask questions. 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, if one or more of these risks or uncertainties materialize, or if our underlying assumptions prove incorrect, actual results may vary materially from those we projected or expected. In providing these remarks, we have no obligation to publicly update or revise any forward-looking statements 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 December 31, 2020, was $137.7 million of borrowed funds and $5.7 million of letters of credit. Our net debt as of December 31, 2020, 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 stayed 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 two 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 debt-to-EBITDA ratio rose slightly to 2.68 times. On April 16, 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 also rose 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 quarantined 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 in Oaktown, costs were $29.84 versus the year before at $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 prices being up 44% year-over-year. As of the end of January 2021, Illinois Basin utility inventory levels had 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 due to the cold snap affecting most of the nation. This return to normal was further displayed by Duke Energy and Southern Company services, two of the largest utilities in the nation, coming out for requests for proposals to buy coal over the last few weeks. Though Texas received the majority of the nation's attention over the four-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 in the transition to carbon-free electricity. One call I saw last week of roughly 2,000 voters conducted by Council found that 7% to 10% of registered voters support maintaining baseload on-demand power plants such as coal plants to support the reliable supply of electricity. In the last seven months, California and Texas, the two states with the highest concentration of renewable generation at 30%, have both experienced multiple rolling blackouts. We acknowledge the greening of the grid, but believe that coal will play an important role in supporting the grid for many decades to come. With that, I will open up the microphone to questions.

And the first question comes from Lucas Pipes with B. Riley Securities.

Brent and team, good job on navigating this very difficult past year. I wanted to follow up on the comments you just made regarding the storm and the renewed purchasing activity. What’s your outlook for coal burn this year, specifically on a year-on-year basis? How sustainable do you think it is as we look at 2022? Is there going to be continued erosion, given the plant retirements, kind of at the stage where we are today? What's your outlook for coal burn this year and next year? Any particular comments on the 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 timeframe, coal plants really dispatch. I mean natural gas prices were down around $1.50 per as people stayed at home. What we saw is coal inventory levels at our customers grew dramatically higher, especially towards the end of May and mid-June. Since then, inventory levels have been declining from that peak every day since. We're happy with what we saw data wise at the end of January. We haven't seen the end of February coal inventory levels yet, but we know with the record amount of cold weather everywhere, those inventory levels got drawn down further. 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 saying it's great yet, but it has certainly improved from where we sat six months ago. We've seen other coal companies come out and say that they have booked export shipments of coal. I don't think anybody expected to ship exports this year. The LNG pricing got so high in December, and I think the market got up to $32 an MMBtu, which is a record. And so coal exporting for various reasons has 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. Some of that has been a fair amount in Indiana that looks to be permanent. So, I think the utilities have been long and wrong for quite some time. Now they are kind of playing a wait-and-see approach, but we think they have to buy coal at the end of this year. They're likely going to try to get through the summer and just see how strong the summer burns are before they really come in and buy big volumes with spot purchases here and there. We expect our sales to be considerably stronger in 2022 than they will be in 2021, based on what our customers are telling us about their open positions and from mine closures that have typically supplied markets which are no longer operating. So from that perspective, we see our coal sales being stronger in 2022 compared to 2021.

That's very helpful. Another topic I wanted to touch on is M&A. 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 I would be curious to see if something has 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. 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 offline. The lower-cost mines are producing more. That’s just the natural progression, especially as we see power plant closures over the next decade or two. Yes, I think we see it. Capital for fossil fuels is certainly more challenging than in years past, but it is available. We will see what the market brings.

Okay, that's helpful. Brent, I'll ask a final one before I turn it over. In terms of the outlook on natural gas, you've always been able to look a little beyond the corner in terms of what's coming your way in terms of the price on the competing fuel there. What's your analysis today about natural gas prices? Obviously, it's 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. Then in 2020 certainly brought challenges for everyone in the energy space. That forced a little more capital discipline into the oil and gas producers. We still see productivity gains from some of those producers, but we're starting to see some of the Marcellus and Utica become pipeline constrained. It’s going to be interesting to see if future pipelines can be built. I think the non-power pipeline has a chance of getting built. The Atlantic Coast pipeline might get built, but it doesn’t look like that's going to be the case. So if you really kind of pay attention to the gas, yes, there is a lot of low-cost gas, but there are very few basins anymore, in my opinion, that have access to takeaway capacity. We have done a good job of building pipelines to get gas out of the U.S. and into Mexico, and building LNG export facilities to get gas out of the country and into Europe and Asia. Those facilities were running wide open in the last few months. That’s been somewhat of a relief to get that gas out there. Gas prices are up 44% year-over-year, which means coal plants are going to burn more, right? They’re going to dispatch at a higher percentage, the higher the price of gas is. Looking at the reliability perspective, it’s going to be interesting to see. Back in August, California had multiple rolling blackouts, and their renewable profile is a little over 30%. We saw in California several natural gas plants slated for retirement. But as they’ve had reliability issues, they pushed those retirement dates out. A similar narrative can be made for coal, as these plants are already built. They’re already paid for. The coal plants must be used for transitioning to greener sources over time to stabilize and back up the grid. The risk of shutting down coal and building a new gas plant now is that you may create stranded assets, 10, 15, or 20 years down the road when they’re not reaching their full amortization spans. Many politicians are starting to see that if they let people sit in the dark, they’re going to lose their leadership position. We’ve seen this in California, Texas, and any leader who lets people sit in the dark quickly loses their position. That’s what we’re seeing now. Legislators across the country are talking to ISO operators like MISO in the Midwest and others and asking how this cannot happen in their region. It comes back to the diversity of supply. Texas has a lot of gas generation, but they could not get gas to their plants. The local price of gas was extremely high, which is contributing to the problem. We hear from MISO in Indiana that they’re at 10% renewables and they want to get to 30%. It’s tough, and the building of transmission lines takes a long time. The Biden administration is working on speeding this process, but any power line build is often met with public resistance. So, we acknowledge the greening of the grid; we just think this transition will take considerably longer than what media and politicians would have you believe.

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 ability to flex production up, given the uncertain environment but with a little bit of an upward bias? What is the marginal cost on doing that per ton?

Well, we do have the ability to flex up to over 8 million tons. In most manufacturing and mining, the incremental cost would be negative because our costs 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 a number that we don’t really want to disclose from a competitive point of view. If you look back over the history of our company, when we run over 7 million tons, you typically see an average cost structure in the mid- to lower 20s.

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

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

We have one customer in particular that tells us their model shows that their dispatch could be anywhere from 7 million tons to 13 million tons in a given year. Typically, what they'll do is try to buy towards their minimum burn and then fill in the balance with spot sales or potentially longer-term sales once that burn forecast really starts to materialize. We think this year is one of those years where utilities are buying at the minimum levels. It's been once bitten, twice shy as last year, nobody saw the pandemic coming. They have open positions in the back of the year, so we're expecting to participate in that. We know there's significant open positions with our customers starting in 2022. The gas market will continue to set the size of what that market opportunity is.

You mentioned the customer survey. If I understood it correctly, people are obviously very upset about the lack of stability and electricity supply in different parts of the country. Do you have an idea from your customers, the people who make the decisions tend to be the right commissioners and often influenced by political figures? Do you think this is going to reach that level? Or has it already reached that level?

Texas is an unregulated market compared to the regulated market, by and large. The decisions to build a plant often lean towards natural gas. We’ve seen proposals from customers to shut coal plants and build gas plants. First, legislators are saying, wait a minute, does it make sense to build a gas plant when we are trying to reduce carbon emissions? Therefore, we might favor coal. These plants are already built; they’re already paid for. You should use coal to transition to greener sources while maintaining stability and reliability for the grid. There’s a risk with gas plants of becoming stranded assets in the future, which brings many risks we should consider. You would need to have reliable assets that can provide baseload generation when needed. You may see some changes in thoughts from legislators as they authorize projects in advanced areas with more renewables. Recently, we’ve seen MISO reallocating the capacity factors of wind due to reliability issues. They’re trying to ensure resources are available in the grid so there’s no failure.

That's really helpful. I appreciate it, really insightful. To summarize, what does that mean in terms of the fate of coal plants as they get their long-term retirement dates? Do you think they'll last longer than expected?

I think you can look to California, where they had four gas-fired power plants slated to close this year. To my knowledge, all those plants are still in place and operational. Leadership knows that if you let people sit in the dark, you will lose jobs. Our goals and targets are noble, but we acknowledge that reaching them is complex and will take more time than many people realize.

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

I was wondering if I could ask a couple of company-specific questions. First, if you could talk about the contracted sales that you expected in Q1, which was a little over $2 million, and it came in at $1.6 million. Could you talk about that a little bit? Also, discuss CapEx in 2020, and what you're projecting in 2021 in terms of the split between maintenance and growth CapEx, and any details on what that growth CapEx entails?

So I'll take the first on coal sales. I think you said first quarter, but I think that meant fourth quarter. We were expecting $2 million for the quarter, but due to a lack of demand, customers came to us, and we were able to negotiate extensions to push terms out where we would sell more tons, adding in some cases up to three years to contracts. We reported this in the management commentary, that our total contract position has grown significantly. One of the contracts even went as far out as 2027. On CapEx, I’ll let Larry answer that.

Yes. The CapEx investment for 2021 is around $13 million, with a little less than half allocated for a man drop elevator in Oaktown 2 that we are building to improve access to production. We think that investment will have an outstanding payback, typically less than two years. The other growth CapEx is still not ready to disclose at this time.

Regarding the elevator, once we start mining five miles out, it makes sense to put in an elevator to get our people much closer to the operating phase. As mentioned, it has a payback under two years since it saves significant labor time.

Okay. And I guess just a follow-up on whatever project is not disclosed right now. Is that commitment already made, or are you waiting to see how 2021 develops in terms of growth expectations?

Right now, it’s a placeholder. We are in negotiation. If we are able to develop that project and secure contracts, then there will be a capital expenditure there. We think that it is likely announced once we choose to finalize the budget.

Next question comes from Sam Serio, who is a Private Investor.

The question regarding contracted prices: I think this was touched on in the last question. Prices are 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 just two different factors that aren’t related?

The contracts for 2021 were most of them entered into way before the natural gas prices went up. That’s the reason they are a little lower than before.

And then the second question was, I believe there were some local news articles about a storage facility down in Indiana by a Duke Energy plant. I was wondering if there was any more color on that or any news or development?

We built a rail facility in Princeton, Indiana, which is right next to Indiana’s power plant. This is where we truck coal to the NS railroad for various markets. We have a lot of land there, and it is designed and permitted to store coal for customers as needed. Currently, we don't have any coal storage for customers at that facility; however, we do have some 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.

I just want to thank everybody for their interest in Hallador. We will continue to try to generate positive cash flow and pay down debt. That's the direction we've been headed, and that's the direction we'll continue. 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.