Good afternoon, and welcome to Hallador Energy's First Quarter 2020 Earnings Conference Call. I'd now like to turn the conference over to Becky Palumbo, Director of Investor Relations. Please go ahead.

Thank you, Grant. Thank you, everybody, for taking the time to join us today to discuss our first quarter 2020 results. As a reminder, this event is being webcast live, and you will be able to access a replay of this call on our website. We filed our first quarter 2020 Form 10-Q yesterday afternoon, and it is now posted on our website. Participating on today's call is Brent Bilsland, our President and CEO; and Larry Martin, our CFO. Larry will begin today with a financial overview of the quarter, followed by Brent with comments on operations and market perspective. After they complete their remarks, we will open the lineup for Q&A. Today, our remarks will include forward-looking statements that are subject to certain risks and uncertainties that could cause actual results to differ materially, for example, our estimates of mining costs, future coal sales, and regulations relating to the Clean Air Act and other environmental initiatives. We do not undertake to update our forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by law. And with that, I'll turn the call over to Larry to begin his quarterly review. Larry?

Thank you, Becky. Good afternoon, everyone. I'm going to start with our operating results for the quarter. For the quarter, we had a net loss of $3.7 million or $0.12 a share. I would like to point out that $3.9 million of our losses were due to fuel hedges and interest rate swaps that are non-cash. Our free cash flow for the quarter was $6.8 million. Our adjusted EBITDA was $13.9 million. We decreased debt by $12.1 million for the quarter, and we paid dividends in February of $1.2 million or $0.04 a share. I would like to go over the definitions of free cash flow as net income plus deferred income taxes plus depreciation, depletion and accretion and our 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 EBITDA plus stock compensation, ARO accretion and our change in fair value of hedges less the effects of our equity method investments in Hourglass Sands. At March 31, 2020, we had $168.1 million of bank debt. Our net debt with our net of cash was $160.1 million, and our debt to adjusted EBITDA leverage ratio was 2.93x. I'll now turn the call over to Brent Bilsland, our CEO, for comments on the quarter.

Thank you, Larry. Thermal coal export prices collapsed in the second half of 2019, pressuring domestic steam coal pricing. Now we do not participate in the thermal export market, but when competing tons go overseas, they return to the domestic steam market and compete against our tons. Additionally, natural gas prices marked their lowest levels in 21 years during the first quarter of 2020. Top that all off with most of the United States and the developed world closed and sheltered in place for 8 to 10 weeks during part of the first and second quarter. These challenges we have experienced in the last several months are of historic proportions. The combination of these extreme events led us to take proactive steps to increase our financial capabilities, so that we can ensure consistency at a time when the world is experiencing great volatility. In anticipation of shipment delays and potential production interruptions, Hallador has amended its credit facility to provide $55.4 million in liquidity as of March 31; suspended its dividend; received a $10 million loan under the Paycheck Protection Program; and permanently closed its Carlisle Mine. We took these decisive actions as power demand has experienced a dramatic decline in the first and second quarter. MISO, where 78% of our customers sell their power, is forecasting power demand in their territory to be 10% lower for 2020 on an annualized basis. But at times, demand has been down up to 30%. This has led to increased inventory levels at both our customers' locations and our mines. Thus, our revenue has been delayed until our customers can receive shipments. Accordingly, we have amended our credit facility to allow for higher levels of leverage, allowing us to access our full credit facility. As part of our credit facility amendment, we agreed to suspend our dividend until our leverage ratio falls below 2x debt to EBITDA. On April 16, Hallador received a $10 million loan under the Paycheck Protection Program. According to the current guidelines from the SBA and the U.S. Treasury Department, Hallador has appropriately qualified and received said funds. Hallador is utilizing the PPP funds to pay 2 months of payroll and other covered expenses. Under the terms of the CARES Act, the company expects a portion of the loan to be forgiven by maintaining current staffing levels through June 30, 2020. During the first quarter, we idled and permanently closed the Carlisle Mine after experiencing 18 months of negative free cash flow at the mine. This decision will further reduce our overall cost structure, maximize our per ton margins, and reduce current and future CapEx by utilizing $23 million of Carlisle equipment at our Oaktown mine. As we reduce coal and parts inventories, we will generate significant cash to be utilized for debt reduction. The idling and closure of the Carlisle Mine contributed to our elevated operating cost of $31.67 during the Q1 of 2020. However, Oaktown costs for the quarter were $29.92 per ton, in line with our prior guidance. Shipments for the quarter were 1.5 million tons, or rounded it was 6.1 million tons annualized. We have another 5 million tons sold for the balance of the year, which we expect to be weighted towards the second half of the year. From a market perspective, we are encouraged by forecasts showing a reduction in gas supply later this year. It is estimated that 40% of the 95 Bcf per day of U.S. natural gas production comes from associated gas produced in wells targeting oil production, which would translate to 38 Bcf coming from associated wells. According to Evercore, active frac crews in the U.S., which we think is a helpful proxy for new oil and gas production activity, will decline 75% from the first quarter of 2020 to the third quarter of 2020. So 80 crews dropping to – or excuse me, 315 crews dropping to 80 crews. As of May 4, Baker Hughes reported that rig counts for drilling and oil and gas have declined from 1,800 – excuse me, 1,085 rigs at the end of 2018 to 408 rigs today, a 62% decline. Over the same time period, gas targets have declined 59% or gas targeted rigs have gone from 198 rigs to 81. Energy Ventures Analysis has stated that a 1 Bcf per day gas supply decline equates to roughly 23 million tons of coal demand. While analysts forecast all agree a decline in associated gas is imminent, a wide spectrum of opinion exists regarding the amount of associated gas decline, the velocity of the decline, and the duration of the decline. Forecasts on the magnitude of the decline range from a conservative 4 Bcf per day to a high point of 16 Bcf per day. JPMorgan and Goldman Sachs have both recently forecast gas production levels will decline by 4 to 6 Bcf per day. But what if 16 Bcf is correct? The coal industry is not capable of bridging such a large reduction in gas supply if the 16 Bcf per day is correct. During the last quarterly call, we discussed the magnitude of coal mine idlings and closures in 2020, in particular, for the Illinois Basin. Since January of 2019, 15 million tons of coal production has been announced that is idled or closed, 80% of which has permanently closed. We estimate another 15 million tons of production has come offline with no public announcement. In totality, roughly 30% of 2018's Illinois Basin production is not currently operating. And since our last call, we have seen numerous additional mines temporarily idled for several weeks at a time due to reduced shipments from lower power demand. Some of these temporary idlings are likely to be extended. While difficult to currently project the amount of volume this takes out of the market, it is significant and shows a definite willingness to adjust production to current demand. So in summary, we certainly have experienced dramatic markets as of late, and we are impressed by the speed at which the gas and coal markets appear to be rebalancing. We believe that Hallador has taken the necessary steps to ride out the storm and continue to generate positive cash flow for its shareholders. No small task in these challenging times. With that, I'll conclude my prepared remarks and open up for Q&A.

Our first question will come from Lucas Pipes with B. Riley FBR.

I hope you all are doing well and staying safe. Brent, I wanted to discuss your comments regarding natural gas. Could you please reiterate some of the numbers you mentioned about the potential supply loss and also elaborate on that in relation to the potential decline in demand? Specifically, how much could have been lost due to a lack of LNG demand or lower domestic power demand? Additionally, how would you assess the net impact on coal considering the changes in the natural gas market?

To summarize the numbers, we estimate that the natural gas supply is around 95 Bcf per day. Annually, 1 Bcf is approximately equivalent to a demand of 23 million tons of coal. Analysts have suggested that gas supply may decrease anywhere between 4 and 16 Bcf per day, primarily linked to associated gas from oil wells. Major firms like JPMorgan and Goldman Sachs commonly point to a figure of about 5.5 Bcf. However, market fluctuations are extreme, such as the oil price dropping from $60 to negative $37 a barrel, which is unprecedented. There have been concerns about running out of oil storage in the U.S., and while we've approached that situation before, it hasn’t fully happened. Additionally, gas storage hasn’t kept pace with production, representing a smaller portion of the overall supply now. As for the market recovery, capital has certainly tightened for oil, gas, and coal, making this an unusual period where all demand has slowed significantly at the end of Q1 and the beginning of Q2. U.S. coal needs to operate close to its capacity next year. However, the journey to reach that point will be unpredictable. If U.S. coal production is set at 565 million tons, data suggests that, with a maximum gas supply drop of 16 Bcf, we would require around 400 million tons of coal, a demand that U.S. coal production cannot meet anymore. Looking forward, there is a potential turning point. Regarding LNG, there are plants being built, and while 90% of it is under contract with 10% in the spot market, current prices in the overseas market are not favorable. This may have reduced demand by up to 1 Bcf, but not significantly more than that. If infrastructure developments proceed, we could see more plants constructed. These markets are under extreme pressure, but there are positives—exports have returned, the winter was mild, gas prices hit two-decade lows, and despite lockdowns, we maintain a positive cash flow and strong forward contracts. To illustrate the recent price changes, on April 2, the spot price for gas was $1.55, while the January future price yesterday was $3.02, showing significant price swings. It appears that coal will be competitive again next year, which means coal plants will be prioritized over gas plants. However, we’re uncertain about when coal buyers will re-enter the market, as they currently have excess supply. That’s why we aim to maintain liquidity on our balance sheet to navigate through these challenges, and we feel optimistic about reaching our goals.

That's helpful. In terms of the chain of thought here with the light at the end of the tunnel, what is unfortunately a seeming overhang for the thermal coal space is the amount of inventories on the ground at utilities. How much concern does that give you? If it was pushed out, kind of the impact from these higher gas prices, 6 months, 12 months. In a way, how much longer will it take for things to get tied in coal given the amount of coal inventories?

In Indiana, Duke Energy is reducing its inventory by burning off coal at a time when gas is being prioritized over coal due to current and upcoming gas prices. We believe that Duke, being the largest utility in the state, is taking appropriate steps to align its inventories. Other utilities are also reducing their inventories by running their plants more, which gives us hope that these actions will help balance the coal market in Indiana by the end of the year. However, the extreme fluctuations in the market make it difficult to accurately assess the changes in gas supply, the rate of decline, and the duration of that decline, since these figures can be substantial. There's a variety of analyses out there suggesting that the oil and gas sector may stop operating old wells, which produce more gas than new ones. It becomes challenging to determine a precise timeline due to the lack of data points. While we can assert that the situation is trending positively, there remains a significant amount of uncertainty, which is why we have been focused on increasing liquidity in our balance sheet to navigate this challenging period.

Very helpful. Now looking at your contracted position for 2021, 5.1 million tons; 2022, 5.3 million tons. So assuming the case that things kind of stay pretty dismal, be it that yes, supply-demand, as you say, there's a ton of uncertainty. So in kind of the downside event where bull markets don't really tighten and try to stay depressed, could you run at that 5.1 million, 5.3 million ton level without a material impact to your production costs?

So we've closed the Carlisle Mine, and we're focused on the Oaktown mine, which has the lower production, lower cost profile. Now we've been running that. We've got 4 units running at Oaktown, I guess, capable of 7. And like I said, we've kept the cost under $30 a ton. I was happy with the numbers we saw in April out of it. So we feel pretty good about that. I certainly think we can do better if we can get volumes up. But the thing about these markets is, every time markets are high-priced, I think it's going to last longer than it does. And every time markets are low-priced, I think it's going to last longer than it does. So we're preparing for the worst, but we certainly see this change in gas is very material in what's going to happen to pricing. And we've seen so much coal supply come offline. There certainly is going to be a rejigger period, right, where inventories are coming down and people are trying to get mines back online. But it looks like to me we're going to be materially healthier from a market perspective in 2021. And we certainly believe that we will make additional sales in 2021.

That's helpful. So you wouldn't suggest reducing it to 5 million tons or a $9 margin at this point? You don't think that's a reasonable base case right now?

I'm sorry, Lucas. I didn't hear the question very well because you're a little quiet.

No, I mean, it was essentially restating my prior question. So at this point, you're not just running at your contract minimums, locking in a $9 margin or something along those lines. You're still looking to potentially put 6 million tons in the market, including your contracted tons. Is that kind of a takeaway?

I think that we are prepared to run at what our contract minimums are, but we certainly believe we will be making additional sales.

And then last question for me. In terms of the market out there, it doesn't seem like we've seen a ton of supply cuts yet, especially kind of given how bad it's been. And could you share your thoughts on what else you're seeing out there in the basin? Are mines closing down? And importantly, are they closing down for good? I think that's what the market really would like to see here.

We've observed major companies in the industry putting mines on hold for 4 to 6 weeks. For example, one supplier had 5 out of their 7 mines inactive for 4 weeks and restarted 1 last week. The other 4 mines are now in their 6th week of being offline. When they do restart, it seems they are operating at only 55% of their original capacity. They appear to be making careful choices to stabilize the market and align inventories. The market sometimes overlooks this; just because a mine is back online doesn't mean it is fully operational with all units or that longwalls are running regularly. Recently, we also heard about another permanent mine closure from a competitor in Indiana. It's clear that some private companies are struggling financially, unable to pay their vendors, which will eventually lead to consequences. We estimate that around 15 million tons have been announced as closures, with approximately 80% being permanent. This figure might have increased since our last data point in March. Some bankruptcy cases start as Chapter 11 but could shift to Chapter 7, which would significantly reduce market volumes. This is a remarkable time with intense market dynamics at play. Many predict a minor reduction in gas, but I question what if the reduction is more significant, around 10 Bcf? If all these mines attempt to rehire at once, they may find there aren’t enough workers available. This scenario could lead to much higher prices, and it largely depends on how quickly these changes occur. However, predicting the timing of these events is challenging, although we believe the trend is moving in a positive direction.

Our next question will come from Douglas Dethy with D.C. Capital.

Could you just give me an idea in terms of, I guess, your cash flow forecast for the year, not so much maybe on the EBITDA, but just on the amount going out between the interest expense, capital expenditures, and any other major items that should be considered?

Well, as stated in our CapEx or in our quarter, we expect to spend $20 million on CapEx for the year.

Okay. And how about on the interest expense? What do you think that will be for the year, just a range?

11% to 12%.

So that's down from last year, is that correct?

Yes, we have reduced our debt a bit, and we plan to continue paying it down throughout the year. It’s not a significant reduction. Keep in mind that our interest rate swap is part of the interest expense, which has been negative each quarter last year. You should refer to the amount related to the interest rate swap as disclosed in the footnotes and included in the cash flow.

Have you provided any guidance on the cash impact of the government program? You have received the funds, but what will the net income effect be by the end of the program? Or will that depend on your expectations?

They are still working on guidance for that. It seems like the rules change every day, so we are not providing any guidance on that for now. If there are changes, we may release guidance, but for now, the rules are changing daily.

Okay. I mean, some of the changes I've talked about changing with respect to retail establishments. I said it wasn't very well set up for that. Is there anything specific with regards to your industry that is undergoing change?

We initially believed that 80% could be forgiven, which was our original guidance. Since then, we've observed new guidance and we expect more from the SBA. To be cautious, we've refrained from making estimates on what that could entail. Our initial analysis remains unchanged, though we haven't seen any significant updates from their guidance. However, it's still possible that we might receive new information later today.

That is certainly understandable. How much did you receive? I know it was mentioned in the release, but I don't have it in front of me.

$10 million.

At this time, I'm showing no more questions in our question queue. So this will conclude the question-and-answer session. I'd like to turn the conference back over to Brent Bilsland for any closing remarks.

I want to thank everyone for taking the time to join our call today, and we look forward to talking to you next quarter. Thank you.

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