Hallador Energy Company (HNRG) Q1 2017 Earnings Report, Transcript and Summary

Good afternoon, and welcome to the Hallador Energy First Quarter 2017 Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Becky Palumbo, Director of Investor Relations. Please go ahead.

Thank you, Denise. Good morning, and welcome to our discussion of Hallador Energy's first quarter 2017 results. This event is being webcast live and you'll be able to access a replay of this on our website. We filed our first quarter Form 10-Q yesterday with the SEC and it can be viewed on our website. Participating on the call today are Brent Bilsland, President and CEO and Larry Martin, CFO. Larry will open with a brief financial overview of the quarter, followed by Brent with comments on operations. After management completes their opening remarks, we'll open the line for Q&A. 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. Now I'll turn the call over to Larry.

Good afternoon, everyone. I'm pleased to announce that Hallador, for the first quarter 2017, achieved net income of $7.4 million or $0.25 a share. We had free cash flow of $20 million for the quarter, and our free cash flow we define as net income plus deferred taxes, plus DD&A, plus our reclamation liability accretion and plus our stock compensation amortization, less our maintenance CapEx. Our adjusted EBITDA for the quarter was $23.9 million, and our adjusted EBITDA is defined as EBITDA plus stock compensation, amortization and reclamation, obligation accretion. We paid down debt of $6.6 million in the quarter, and we paid dividends of $0.04 a share or $1.2 million. Our bank debt at the end of the quarter totaled $232 million owed to the bank. Our net debt after our cash reduction, available cash was $211.1 million. We estimate that our debt at the end of the year will be between $210 million to $215 million. That would be a debt owed to the bank. And our - at the end of the quarter, our debt-to-EBITDA ratio - leverage ratio was 2.83, which is our Sunrise-only bank covenant as defined in our loan agreement. I'd like to turn over the call now to our President and CEO, Brent Bilsland.

Hello, everybody. Thank you for joining our call. First, I'd like to say that we're very pleased with the results of our first quarter. Dramatic reductions in cash cost per ton allowed Hallador to generate strong free cash flow of $20 million and adjusted EBITDA of $24 million. This allowed us to continue to pay down debt, maintain our dividend and invest in our business. We attribute Hallador's success to the men and women who choose to work here and their dedication towards maintaining our low-cost culture. Again, we experienced impressive operating costs in the quarter of $23.22 a ton at our Oaktown mine, that translates to $25.53 a ton when you add in the costs associated with Ace, Carlisle and Prosperity. In 2016, our cost averaged $27.87 at Oaktown and $30.56 a ton once Ace, Carlisle and Prosperity were considered. This $5 a ton reduction in cost was due to two primary factors. First, we made a conscious effort to produce more tons in the first six weeks of the quarter in anticipation of a stronger market demand. Secondly, we have added new haulage equipment to some of the units at the Oaktown Mine. Those units are seeing production increases of roughly 30%. Both factors, combined, led to a 25% increase in production in the first quarter over our 2016 average production. Late in the third quarter, we anticipate the arrival of additional haulage equipment and the implementation of a new elevator at Oaktown 1. Thus, we expect both investments to contribute towards maintaining our low-cost structure. Thus, going forward, we have decided to reduce our cash cost guidance by $2 a ton to a range of $26 to $28 a ton. For the balance of 2017, our CapEx budget is $27 million, which includes $16 million in maintenance CapEx. Additionally, we expect our SG&A to be $8 million and cash costs associated with Prosperity and Carlisle to be $5.5 million for the balance of the year. As previously mentioned, in the first quarter, we sealed off a large portion of the Carlisle Mine and a lot of costs associated with that mine are now behind seals. Thus, the cost of holding Carlisle idle has been greatly reduced. Looking to our balance sheet. Our strong free cash flow allowed us to pay down debt by $6.6 million, deleveraging our balance sheet to 2.8x debt-to-EBITDA. Our reduced leverage ratio moved us lower in our credit facility pricing grid, reducing our interest rate by 0.5%. Additionally, our liquidity improved to a healthy $84 million in the quarter. As we turn our attention to market, looking at the demand side. We continue to see a healthier market in 2017 than we experienced in 2016. Natural gas prices have averaged roughly 30% greater than a year ago. Additionally, our markets - in our markets, our customer inventory levels are lower than they were a year ago. As we look at our sales, we currently have a minimum of 6.1 million tons sold for the year and have raised our projections to 6.3 million to 6.6 million tons for full year 2017. Looking at the supply side of the market. Over the past 2.5 years, Indiana's coal supply capacity has dropped by over 20%. We have been involved in nearly all of the supply reductions, either in the form of mine closures such as Prosperity, mine idling such as Carlisle or by purchasing competitors' assets. Some of this capacity will come back online, but most will not. At current prices, we estimate there's an initial 20% of Indiana's production that is in risk of closure in the next couple of years. Utilities have not felt this tightness of supply due to the fact that December of 2015 to February of 2016, and December of 2016 to February of 2017 were two of the warmest winters in the last 30 years. Now typically, the United States experiences two to three warm winters followed by two to three cold winters. Thus, we feel it's a matter of time until hot summers and cold winters return, during which time we believe market prices can move higher. We believe our sound balance sheet, low-cost production profile and our ability to quickly add 65% more production puts Hallador in a unique position to increase profits when weather returns. With that said, I will open the queue up to questions.

[Operator Instructions] The first question will come from Lucas Pipes of FBR & Co. Please go ahead.

Brent, Larry, great job this quarter especially when it comes to costs. And my first question, I wanted to maybe drill down a little bit on that. And I wondered specifically, how sustainable do you think those cost levels are when you think about 2017 guidance? Can we kind of, in our model, think about another three, four years you can hold the line there? Or anything coming down the road? Would appreciate your perspective.

Well, again as we stated, the cost reduction was due to two factors. We ran hard for six weeks in the quarter, so half a quarter, Saturdays basically. And that was an anticipation of stronger markets, which - so we kind of hit the brakes mid-quarter. And in an underground coal mine, we - the harder you run, the lower we can see our costs fall. At the same point in time, we implemented new haulage to a couple of the units. And like I said, we're seeing a 30% increase in production on those units. And because of that, we ordered more cars, we anticipate being delivered with putting into production in the third quarter. So we lowered our guidance.

Cost guidance.

Cost guidance, excuse me, $2 a ton, basically, because we believe the implementation of a new haulage later in the year plus we have an elevator that's currently under construction. That will get our employees less travel time in the Oaktown 1 mine. We think both of these factors move towards lowering our cost structure in an environment where we're running not full bore. If we turn up the tonnage because market demand is stronger than what we have anticipated, our costs can definitely fall back in the low 20s. So what really comes down to is the Oaktown mine going to run at a 6-million ton pace or is it going to run at an 8-million ton pace?

So essentially, if we were to get to that 8-million ton pace, not only which should be generating more revenue, but your costs would also be, if I just heard you right, you said low 20s, right?

Correct. I mean, that's where it was in the quarter. We - like I said, we ran half a quarter at a pretty aggressive pace and our cost average for the quarter was $23 and change. We ran - if we were to run the whole quarter strong, it would have been lower yet. So we're definitely showing that we can - we have confidence that we could do that. The market is not asking us to do that at this time. And again, we think that’s in large part because we look at the - and even you want to go back to the heating season of 2015, it was mild. The heating season of '16 was mild. Last summer, we had a good summer and it was warm. But winter this year was almost, other than December, was almost nonexistent. So if you look at four of the last heating and cooling seasons, only one of those really experienced significant demand. That's not unusual when you start going back looking at 30-year graphs of weather patterns, and it's somewhat like clockwork. We seem to have two to three warm ones followed by two to three cold ones. So we're confident that weather will return, and especially with these gas prices pretty much staying above $3, significantly stronger gas prices than we saw a year ago by roughly 30% and - so coal is in the money in Indiana. It's just a matter of how much weather we're going to see. We think that utilities, by and large, are short and they're waiting to see just how much heating demand comes at them. We estimate, like I said in our projections, that we've got 6.1 million sold. We anticipate we're going to sell another 200,000 to 500,000 tons. That's what we think is going to happen. As we get more weather than that, we'll sell more tons and you'll see more volume and our costs continue to drop.

Got it, that's very helpful. I'd probably ask a few follow-up questions on some of the points you brought up there. But I want to quickly circle up some items on the cost side and as it relates to Carlisle. Brent, in your prepared remarks, you mentioned how you lowered the idling costs. Could you maybe be a little bit more specific? I want to say that in the past idling costs where in the, I want to say, high single digit million-dollar range. If you could maybe give some sort of guidance where those costs would be now that you've sealed a large portion of the mine. And then longer term, what do you think is the prospect of Carlisle? Where do you think it fits in this new domestic market? Would appreciate your perspective.

Well, on the cost side, Lucas, we estimate Prosperity and Carlisle idling costs to be about $5.5 million for the rest of the nine months remaining. And as Brent explained in his call - or in his remarks, we've sealed a lot of the area that those costs were coming from. So we're lowering our - like I said, they'll be $5.5 million the rest of the year for Prosperity and Carlisle. In the past, that number was $10 million total for the year.

Yes. So if you want to look at the Carlisle Mine, this is Brent, yes, when we idled the mine in 2015, we had roughly 88,000 feet of main opened up heading in multiple directions. We idled in, I think, July of '15, we sealed the southern portion of the mine. Then we announced here in our 10-K that in January of this year, we sealed - we decided to seal the northern part of the Carlisle reserve and I don't have that exact number in front of me how many feet that was, but I'm going to say in the neighborhood of 45,000 feet. But it was more than that, we just were having a lot of falls in those mains, and quite frankly, we've - it was becoming a significant safety concern. When we look at the mining costs of that mine, the northern portion of the reserve was more expensive to mine than the western portion, which we have left. So anyhow, we decided to seal that mine off, and in doing so, we really shrink the footprint that we had to inspect and maintain. And going forward, we think our - you now have a mine that roughly only has three miles of main opened up and the mining in front of it looks really good. So I think our cost structure there, when we do fire Carlisle back up, looks something more like it did a few years ago because we certainly - it looks more like a new mine, a lot less out bye to have to maintain. Now we're doing - so we did lose a little capacity. Carlisle went from putting out 3.3 million tons, we think its capacity now is 2.5 million, but we think its cost structures is much more reduced. The part - the second part of your question, I think, was - I think what you're alluding to...

Where it fits in on the demand side, I would say.

Yes, I think that's part of what makes us unique. When you look at coal companies, here we are, we've got 10.5 million tons of capacity and the cash flow we're putting out is generated by 6.1 million tons. I just don't know of too many other companies that have the gun cocked, so to speak, on another 65% increase in production. As far as Carlisle is concerned, it's ready to produce coal. We are waiting for a strong enough market demand to justify hiring employees and putting it back to work. Our crystal ball is that does happen in 2018, but it's really going to be decided by the market and how much of business we can secure. And that probably won't be decided until after the RFP season from this that'll happen this fall, but we hope a warm winter - excuse me, a warm summer and a cold winter, and if so, we're going to bring that asset back online.

The next question will come from Mat Klody of MCN Capital. Please go ahead.

Great quarter in terms of production and costs. Keep up the good work there. Just want to get your perspective on what you're seeing in the M&A environment in terms of activity, changes in seller expectations or not over the past year. You guys have picked up some good assets in the past and appreciate your perspective there.

That's an interesting question. On the M&A side, we think that consolidation continues to happen in the Illinois Basin because gas has become more of a competitor, which I think will force more consolidation in the coal industry. As far as what are the attitudes of buyers and sellers, that's really on a case-by-case basis. We're always willing and able to have those conversations with would-be sellers. Then like you said, I mean, we've been fairly active, I think, as much as anybody in the state of Indiana. When I look around at what production has come off-line, we've been involved in nearly every deal. We did see one private here, in the last couple of months two privates kind of go together. So things are happening. There seems to be money. A year ago, nothing was really happening, everybody was in bankruptcy, capital was kind of frozen up for coal. Since that time, we had a different administration. Gas prices are higher. A lot of the - if you look at the coal space, it's a lot - has a lot less leverage on it than it did a year ago, mostly due to bankruptcies, but those of us that didn't go through have continued to pay down debt as well. So I think that the environment is certainly more hospitable for M&A activity than it was a year ago.

[Operator Instructions] The next question will come from Arthur Calavritinos of ANC Capital.

Just a question. We know how the winter was and we had a great December, but you guys know better than us, Jan and Feb, and March was cold. But seeing the reaction we are having in the gas, I'm look at the curve right now, are you guys surprised at what we're seeing in the nat gas market in terms of pricing?

Well, nat gas has - is certainly robust right now. But if you look at - it depends what number you focus on. If you're focused on inventory levels versus five years' supply averages, yes, we have slightly more gas around than the 5-year average. On the flip side of that, production is lower than a year ago and uses of gas is higher than a year ago, so - and we're achieving that with fairly mild weather so far this year. So I think - and at the same point in time, again, we feel that utilities are short. So everyone's kind of sitting around, waiting to see what the summer brings temperature-wise. Some people are saying, well, warm winter, warmer summer. If that's the case, nat gas prices are too low, so coal prices are too low. We have - if summer doesn't show up, then prices certainly can move lower, but that seems to be the attitude we're seeing right now. Like I said, gas storage levels are a little high from a 5-year average, but considerably lower than where we were a year ago. And I think it's the pace of demand and the pace of - we have more demand and we have less supply of gas than we did a year ago, so that's what's making up that dynamic.

At what price - I mean, what ballpark price you guys - I mean, you said 6-and-change tons and you can ramp it up, I think, said 65%. At what price do we get the lion's share of that, you think, of that 65% you talked about earlier when more ton's going up?

Well, I think it has more to do than just price. I think it has to do with what kind of terms can we see on the deal. We don't want to go out and hire employees for six months' worth of work. We're - we try to - whatever we do, we try to make it a longer-term, consistent-type operations. So like I said, we're not looking for spot business to bring that online, we're looking for "can we piece together" contracts that we think are sustainable.

The next question will be a follow-up from Lucas Pipes of FBR & Co.

I actually wanted to follow up on the previous caller's question and that is gas prices have been very strong. And in your local market, Brent, where do you see the breakeven between your guys' customer plants and natural gas, assuming, call it, $40-or-so pricing. Would appreciate your perspective.

Lucas, can you repeat a part of that question. I'm not sure I grasped exactly what you're asking.

So what - so your customer, the plants of your customers that you supply, what is their break-even price with natural gas at Illinois Basin coal prices are up about $40 a ton?

Well, I mean, that just varies so greatly because we've got coal plants that are 10 miles up the road and we've got two customers currently that are roughly 1,000 miles away. The heat rates of all those plants differ substantially. So I think, in general, if we're talking generalities, I would say coal plants in Indiana are in the money, in the $2.66 gas range and we're currently - I mean, looking at last year, last year, natural gas prices averaged $2.49 for the year and the state of Indiana had coal demand of roughly 28 million tons. So traditionally, Indiana coal demand is somewhere in the 37 million range. So you're seeing a 9-million ton swing due to gas prices. Now a lot of coal last year got delivered and went into inventory at the utility level. So this year, we have higher gas prices, coal is in the money, but customers are shipping a little bit early on their contracts and they're pulling down their inventory levels. So when we talk about a stronger market, yes, we haven't moved more tons than we moved this time last year. Substantially, it's roughly the same. But when we look at health of the market that we'll be selling into, we have gas prices 30% higher, we have coal inventory levels at our customers that are, depending on the customer, but roughly 20 days lower. So they've been burning up a lot of inventory and shipping early on contracts to try to stay out of the market. The flip - the counterargument to that is if you have a little heat here, you're going to see a lot of customers that have to come rushing back to it because they don't have it purchased. Everyone's trying to play it shorter than they traditionally have in the past. And because of the mild winters and an even one mild summer thrown in there, that strategy has worked. If weather returns, somebody's going to get hung out to dry. And we feel that we are in a unique position. When you look around at other suppliers, there's just very few suppliers that have as much coal production ready to go as a percent of their overall supply. I mean, we've got another 65% we can turn on. I think that's a very large percentage compared to what other suppliers have, which is what gives us the comfort - maybe comfort's - which we think improves - increases the probability that Carlisle comes back online next year.

Yes, that's a very helpful perspective. So in a way, when gas prices move, you may have much more exposure to that than maybe some of your peers, so that's quite an interesting angle [indiscernible].

And if you look at Carlisle coming back online, I mean, if you look at our cost numbers, holding that idle is costing us over $2.20 a ton, $2.30 a ton. So if we can get it to carry its own weight instead of being a guaranteed loss, it helps improve our margins.

Yes, got it. Okay.

So that's certainly our goal and we're working towards that.

[Operator Instructions] The next question will be a follow-up from Arthur Calavritinos of ANC Capital.

Just on that last - the follow-up on the last Q&A thing you had here. So if you've got a utility and said you're playing it short and whatever, gas prices move, cooling demand does what it does. It gets interesting with you guys, right, because it's sort of like - if a utilities really wanted all the stuff now, but you guys have so much capacity, you need to turn on Carlisle and hire guys for only six months, it gets really interesting on your side, right, I mean the way I'm thinking about it because utilities is just - from what you've been telling me for over the past two years or so the utilities sound like they feel they could snap their fingers to get as much coal as they want without really understanding your business and your cost structure, what you have to do and how much stuff you've done in the past two, three years. Is that sort of - I mean, again, I'm generalist analyst, but sort of what's going on here in a scenario like that?

Arthur, you're breaking up a little bit and I'm not sure I understood what the question was.

Yes, let me repeat it. Hope I'm not breaking up on the mobile here, but what I'm saying is if there was demand, right, the utilities, from what you're saying, sort of are assuming they can get as much coal as they want without really understanding your business and what you guys have had to do with costs, right? Because as you said earlier in the call that you don't want to hire anybody, and I get that and I understand it, I agree with it, for six months just to have the utility go away, right? So it gets interesting in terms of the demand cycle coming back if we have this summer, right?

Yes. I think that, again, we think the supply has come off-line, the utility has not felt the tightness of that because they've been bailed out by mild weather and cheap gas. The cheap gas is not currently the environment we're in, so coal is competing against coal right now. Coal is dispatching over gas. The question going to be is how much weather we're going to have, how much - what will that do to demand and our prediction is because of the capacity that's come off-line, that the market will get tighter quicker than what we've experienced in the past and prices will rise when that happens so [indiscernible]

So for each - yes, but to paraphrase it, excuse me. So for each, whatever, $0.10, whatever, $0.05, $0.01, whatever it is, in natural gas pricing, all else being equal, it's a more high-powered move per move in natural gas as competition with coal versus in the old days, right? So for each move - the each movement in nat gas is more high-powered, if you will, to multiplier effect - not a multiplier effect, but it's - I'll use the term multiplier, so better multiplier for you guys than it was in the past. Like if we move $1 on nat gas in the summertime versus five years ago, it's much more operating leverage than it was back then?

Well, but in general, the dynamic is coal is in the money in Indiana in the mid 2s. Coal is in the money in Florida in the mid 3s. So what you're really going to see is if gas prices were to move up $1, suddenly coal plants in Tennessee and Georgia and the Carolinas suddenly go from dispatching to gas first and coal second to dispatching to coal first and gas second. And so there's a huge, huge demand that would occur when that happens, right? So if you think of the utility buyer is challenging to figure out what your plant is going to dispatch in the state of Indiana, it's extremely challenging when you step out to the Carolinas and anywhere in the Southeast because you're closer to the cheap gas and you're closer to the more expensive coal. So there's more transportation to get all that basin coal out of the market. So that's where $0.20, $0.30, $0.40 moves in gas price during the summer months when you have heating demand, or cool weather in the winter months, it can have a dramatic effect on changing what the overall demand could be. I mean, there's - I think if you look at the southeast system for - take the NS railroad. You have 60 million tons of demand - there are 60 million tons of capacity that typically burns 20 million tons a year. So if that flips where suddenly coal's in place of gas, there could be 40 million tons of new demand. Now I'm not predicting that. I'm just saying if gas prices move higher, that's the potential and especially, when you look at an Illinois coal basin, that the entire production of Indiana, Illinois and West Kentucky is 115 million tons. So it doesn't take - a 10-million ton move is dramatic.

The next question will come from [indiscernible].

My question is what kind of term contracts do you need to turn that Carlisle back on? You said six months is not enough. Do you need three years? Also in terms of pricing, do you need a firm pricing? Or do you need to just have the term contract, in other words, just the volume commitment?

Well, I think it has less - first of all, I don't think there's a lot of utilities that are booking a lot of 3-year contracts. They certainly are requesting proposals that far out. It'd be interesting to see if any of them actually book business that far out because utilities in the last few years, I think, has moved their pricing strategies to a little shorter term just because it's more difficult for them to understand the coal-gas dynamic than it was three or four years ago. So what kind of contracts are we looking for? Again, I think it has less to do with term and more - we're going to look at it as is this something that once we hire people we can keep them employed. What are the odds that either we get a longer-term contract or we have a shorter-term contract, but feel that the environment is such that we can keep that production or at least have a very high probability of keeping that production online. We'll just have to evaluate what the market is at that time and feel, in our opinion, is it sustainable or is it a flash in the pan.

[Operator Instructions] And I'm showing no additional questions at this time. We will conclude the question-and-answer session. I would like to hand the conference back over to Becky Palumbo for her closing remarks.

Well, thank you, everyone, for your interest in Hallador and participating in today's call. We look forward to seeing what the summer brings us and talking to you at our next earnings call. So have a good day.

Thank you, ladies and gentlemen. The conference has concluded. Thank you for attending today's presentation. You may now disconnect your lines.