Hallador Energy Co (HNRG) 2019 Q4 法說會逐字稿

Good day, and welcome to Hallador Energy's Fourth Quarter and Year-end 2019 Conference Call and Webcast. (Operator Instructions) Please note, this event is being recorded.

I would now like to turn the conference over to Ms. Becky Palumbo, Investor Relations. Please go ahead.

Thank you, everyone, for taking the time to join us today. Today, we are going to talk about our fourth quarter and full year 2019 earnings. If you haven't had time to review the Form 10-K and the earnings release we issued yesterday, they are both posted on our website today. And as said before, this call is being webcast and a replay will be available on our website along with the transcript later this week.

Participating on today's call with me are Brent Bilsland, our President and CEO; and Larry Martin, our CFO. Larry will begin with the financial overview, followed by Brent with comments on operations. After management completes their opening remarks, we will open the line up 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 cost sales and regulations regarding 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.

Also, I would like to remind you that we'll be turning the call back to -- I'm sorry.

With that said, I will turn the call over to Larry. Thank you.

Good afternoon, everybody. Thanks for listening. I'm going to start with our review of operating results. And before I do that, I want to get some definitions out of the way. We define adjusted free cash flow as net income plus deferred income taxes, plus DD&A, plus ARO accretion and stock compensation, less maintenance CapEx and the effects of our equity method investments. We define adjusted EBITDA as EBITDA plus stock compensation and ARO accretion plus the effects of our equity method investments in Hourglass Sands.

Hallador incurred a net loss of $59.8 million for the quarter or $1.95 a share and $59.9 million loss or $1.95 a share for the year. This loss includes $77.9 million of impairment. Without the effect of the impairments, Hallador would have lost $1.6 million for the quarter or a $0.05 a share and $1.7 million for the year or $0.06 a share. We incurred adjusted free cash flow of $8.1 million for the quarter, $29.8 million for the year. We had adjusted EBITDA of $16.7 million for the quarter and $68.8 million for the year.

We increased our debt by $8.2 million for the quarter and reduced our debt $8.3 million for the entire year. We paid dividends of $1.2 million for the quarter or $0.04 a share, and a total of $5 million in dividends for the year or $0.16 a share.

Our bank debt at the end of '19 was $180.2 million. Our net debt at the end of '19 was $171.4 million, and our debt-to-EBITDA leverage ratio was 2.62x.

I will now turn the call over to our President and CEO, Brett Bilsland.

Thank you, Larry. As announced in our press release, after experiencing negative free cash flow at Carlisle for the past 18 months, we have decided to permanently close our Carlisle Mine, which will further reduce our overall cost structure, maximize per ton margins, reduce current and future CapEx by utilizing Carlisle equipment and parts at Oaktown. As reduce -- as we reduce coal and parts inventory, we will generate significant cash to be utilized for debt reduction.

During the quarter, we impaired 3 assets. The Carlisle Mine, the Bulldog reserve and Hourglass Sands for a total of $77.9 million in noncash impairment. The Carlisle Mine represented $65.7 million of impairments as a result of its closure. Additionally, we thought it prudent to impair our Bulldog reserve by $9.2 million, as current market softness has reduced the opportunities to open the mine.

Lastly, due to reduced frac sand pricing, we determined that an impairment of our Hourglass Sands projects was necessary. We continued to sell-through our sand inventory, but have recorded an impairment of $2.9 million. Some investors might have concern that in 2019, we sold a record 8.1 million tons. And in 2020, we are selling 1.4 million tons less. How is selling less of a product a good thing? Well, the answer is, Carlisle produced 1.5 million tons last year at a loss. So in 2020, Oaktown will essentially be producing the same amount of tons as in 2019 without having to support the losses of the Carlisle Mine.

Operating cash flow was $15 million lower than expected in 2019. $7 million was largely attributed to Carlisle's high cost structure, pressuring margins. And we increased coal inventory by $8 million in anticipation of winter shipping season. As we look to 2020, those headwinds either do not exist or unwind themselves.

In 2020, we have 6.7 million tons sold at $40 a ton. We are assuming no additional coal sales for the balance of this year. With the closure of Carlisle, we believe our cost structure returns to $28 to $30 a ton. We estimate our SG&A will run $12 million. Our bank interest will be $13 million, plus we will spend $3 million in Carlisle closure costs. We have reduced our capital expenditure budget to $20 million. We further look to generate another $24 million in cash by reducing coal and parts inventory and other working capital adjustments. Thus, in total, we should create $50 million in cash, which we will use -- utilize to pay $35 million in principal bank payments.

Hallador only has 30.4 million shares outstanding. The warehouse can invest or find a company that is paying down over $1 a share in debt and is trading at a $1 a share. I think this represents extreme value.

On the financing front, I'll remind everyone that we refinanced our credit facility last September and extended our term through September of 2023. So we have plenty of time left in our agreement.

Additionally, when looking to sales, we do not feel near-term pressure to sell coal as we are 100% sold for 2020. Now there are certainly challenges in the current energy environment, but we see markets that are making dramatic changes to return to balance.

As of February 7, Baker Hughes had reported that rig counts for natural gas targets in the Lower 48 had declined 76% year-over-year. I'd like to point out that was a month ago. Roughly half of U.S. gas production comes from these targets. The other half of gas -- of U.S. gas production comes primarily from associated gas from oil targets.

Yesterday, JPMorgan reported that with WTI oil pricing in the 30s, 50% of oil rigs in major basins such as the Permian or the Eagle Ford will come offline and up to 80% of oil rigs in smaller oil basins are coming offline. This is dramatic change.

In the Illinois Basin, we are also seeing significant coal supply response. In January of 2019, 15 million tons of coal production has announced that it is idle 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 Illinois Basin coal production, from just a year ago, is currently not operating.

So we see higher gas prices in the future due to dramatic reductions in drilling and less competition for competing coal supply due to mine closures. So we certainly recognize, again, the challenges in the industry.

We believe Hallador is unique when an investor focuses on our strong sales position, again, 100% sold this year, 79% sold next year, our low-cost structure and our strong cash flow per share.

With that said, I'll open up the phone for questions.

(Operator Instructions) The first question comes from Lucas Pipes with B. Riley FBR.

I wanted to first ask a little bit about kind of the contracting environment out there. Brent, what is your take on kind of how the utilities are approaching this market? Are they in a wait-and-see mode? Are they purchasing tons? And if so, what's roughly the price out there? I think it's something that the market would really appreciate some additional color on.

Yes. I think we've talked in the past about -- there are times in the coal market where the window is open and coal buyers are buying coal, and there are times where the window is closed. And quite frankly, there's just not a market price. And to me, right now, the window is closed. When our burns were weak, export tons came home, gas prices crashed. So I would say most utilities at this point in time are long inventory, slow to pick up inventory. I think they will be looking hard at the summer month burns and looking for gas prices to increase. So that's why we basically are assuming no additional sales this year because we just don't -- I mean there's a few buyers out there, but I think they're at prices that we would not be interested in participating.

Okay. No, that's very helpful. I appreciate that color. And then in terms of the market in the Illinois Basin, you mentioned the competitors out there, what do you think is going to be the supply response? I mean if the market has essentially frozen out there, you're in a pretty enviable contract position, not everyone is in the same boat. How do you think this will play out?

Well, I think we're seeing it play out. I mean that's -- 15 million tons has announced that it's closed in the last 14 months. 80% of that has announced that it is permanently closed such as the Carlisle Mine. There's a lot of production coming offline that there's no announcement for. If you're in the industry, you have people telling you that this mine over here is used to run 7 units, it's now running 2. And so there's a lot of supply response. It really has no public announcement with it. We estimate that to be at least 15 million tons. So you've got almost 1/3 of the Illinois Basin that was producing at the end of 2018 that's not producing today.

In large part -- people look to exports. But I think, in large part, it's just cheapness of gas prices. You've got gas down at unsustainable levels. This is, in my opinion, evidenced by the fact that gas rigs have come off 76% year-over-year. That's a staggering statistic. And now, over the weekend, we see a dramatic shift in the oil prices, which sounds like it's going to last for a while. We're seeing significant response just yesterday, and oil rigs coming offline, frac jobs being stopped mid-frac. The industry is having a significant response, in large part because the oil and gas industry doesn't have the access to capital that it had just a couple of years ago. I mean in the past downturns, that industry would have borrowed or raised equity and those are levers they really can't pull right now. So to me, the only lever they currently have is to rein in their drilling budgets and preserve cash. And that's what we think is happening.

Now decline curves for shale plays, which is the majority of U.S. gas, and oil for that matter, is -- this is a pretty steep decline curves. So -- and I think everyone is still trying to rejigger their model to figure out exactly when and to what magnitude we see supply come offline. But supply is coming offline like I've not seen in my career.

So it's a dramatic time, but we see things coming back into balance. And the good news is, like you said, we sit here, we feel no pressure to sell coal this year. We need to sell another 20% for next year, and we believe that we will see gas prices significantly higher than they are today due to this response in drilling.

This is very helpful. A follow-up -- super helpful, in fact. And a follow-up question on that is, I know you don't have a crystal ball, but if you had to take a guess kind of where gas prices are going to shake out on the back of the dynamics you just mentioned, so that's 1 question. And then 2, what gas price do you think is needed to balance the coal markets? You mentioned utilities aren't buying, coal has been stocking up. Like what is -- what's the gas price we're looking at from what's going on in the energy world? And what's the gas price needed?

What's the gas price needed? It's a very little question. I mean I think that Illinois Basin coal does pretty darn well at a $2.60 gas price. And that would -- at that price, the United States would need 30 million tons of Illinois Basin coal to come back online, that probably doesn't exist -- all that does not exist today. So it is a bit tougher to understand the supply response because we're just seeing things we haven't seen before. We haven't seen where 13 million ton permanently closed in Illinois Basin, another 2 is idled -- announced idled and another 15 or more has kind of idled but hasn't really told anybody. We see people being shifted around and we see units coming offline. We just haven't had -- we just really haven't seen that before. So it's a little tougher going forward to saying where is the new balance. But we know that looking at what coal plants can do in Indiana, 70% usually of our product is consumed in Indiana, that $2.50 $2.60 number per gas at the Henry Hub typically equates to reasonable margins for coal prices back in Indiana and coal dispatching in front of gas in Indiana.

Obviously, higher prices helps our customers that have greater transportation rates such as our Florida market or anything in the Southeast. So we do better, obviously, with those higher prices, but Indiana does pretty well in that mid-$2 range for gas.

Very, very helpful. And I will close it out with 1 last question. Brent, what are you seeing on the retirement front? Is that something that's starting to slowdown? Or -- in terms of tons and specific to the Illinois Basin, what's the outlook on that? Would appreciate your perspective, and thanks for all the color.

So as far as retirement goes, I mean I think that we don't currently today have -- we've seen some retirements and we've seen some talk out there, mostly in the 2026-2028 time frame. We will see some RFPs later this year. We don't know today exactly what those will bring. We saw Hoosier come out and announce in January that they plan to close Merom in '23. But I think that we're also seeing, at the same point in time, FERC kind of come out and telling PJM, you've got to rewrite the capacity market rules, the MOPR rule or -- we need these -- if you look at the U.S. grid, our baseload -- we're replacing baseload assets, coal, nuke, gas, mostly coal and nuke, with -- those are assets that have on switches that are being replaced by wind and solar generation that does not have an on switch. And I think FERC is genuinely correct and they are concerned about this. The rules are being rewritten first in PJM. People -- some people are upset about this. Obviously, it creates challenges for those states that want to go more heavily renewables. But ultimately, something has to back all this stuff up, right? And if you want plants to sit there idle and ready to go to back up this generation, you have to pay it. And you have to pay for that through capacity payments. So we're seeing those rules change.

We've seen the CEO of MISO testify before Congress today before Halloween that he can no longer guarantee that the lights can stay on 8,760 hours of the year because he's having far too many reliability issues and not just on days of extreme weather, just days where the sun doesn't shine and the wind doesn't blow. Suddenly, a large portion of the grid doesn't show up. And those days, we have to rely upon generation that has on switches. Now most of all the new builds are gas, especially in the MISO district. But we are seeing things where more and more people are getting concerned about the reliability of the grid. We saw California really look heavily, and it probably has been more the front-runner of states pushing for more renewable power. But now you have the issues with PJM -- or with PG&E where their response is in moments of high wind, we have to shut the lights off, and that might be for 3, 4, 5 days at a time. How do you run a business if you don't know if you have power?

So this is causing a lot of people to suddenly say, well, hey, renewables are good, but they also have their challenges. Our grid was not designed for that, and we're starting to see the problems that happen when you put an ever-increasing amount of renewables on the system.

These problems will get worked out. I think it will be through higher capacity payments to pay to keep baseload generation online, whether that's coal, gas or nuclear power plants. So by and large, we are of the opinion that nukes will run through their license, but at the end of the license, they will not be renewed. I mean the labor cost for nuclear power plant is just too cost prohibitive. Coal-fired power plants have challenges as well. But at the end of the day, these plants are built, they're in the system, they work very well. You can store fuel on-site versus most gas plants don't have firm transportation. So in the event, and we've seen this up in Michigan a couple of years ago, they had a gas line break during winter, and so they had to shut all the gas transmission off to all the power plants. Nuke and coal took the load at those times. And so these are the scenarios that our ISO operators are trying to understand, trying to model and trying to figure out, but they're all basically saying the rules have to change because we have to value assets that have on switches and can store fuel on-site, because that makes our grid more reliable and more resilient.

So that conversation is happening. It does fly in the face of some of what those in the press would like to see. So you don't typically see those headlines on front page news. So I think that answered your question.

(Operator Instructions)

This is Brent. If there are no further questions, we're going to thank everyone for joining our call, and we look forward to talking to you all next quarter. Thank you.

This concludes our question-and-answer session. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.