CLD
#Good afternoon.
With me today are <UNK> <UNK>, Cloud Peak Energy's President, CEO and COO; and <UNK> <UNK>, CFO.
Today's presentation may contain forward-looking statements regarding our outlook for the company and industry; financial and operational guidance, volumes, prices, demand and costs; the regulatory and political environment and growth strategies; capital resources and other statements that are not historical facts.
Actual results may differ materially because of various risks and uncertainties, including those described in the cautionary statement in today's earnings release and in our most recent Form 10-K and Form 10-Q.
Today's presentation also includes non-GAAP financial measures.
Please refer to today's earnings release for the reconciliations and related disclosures.
Our earnings release is available on the Investor Relations section of our website at cloudpeakenergy.com.
I'll not turn the call over to <UNK> <UNK>.
Thank you, <UNK>.
Good afternoon, and thank you for taking the time to listen in to our Q1 2018 results call.
I'm joined by <UNK> <UNK>, our CFO.
Shipments during the first quarter continued at a steady pace as our customers took their contracted coal.
The cold January increased coal burn, bringing down utility inventories.
But this slowed in February and March with warmer weather.
Our export business ran well, with strong demand from our Asian customers and good performance from the rail and port system.
This allowed us to export the forecast 1.4 million tons during the quarter.
There were no reportable injury during the quarter, at our operations and our rolling 12-month All Injury Frequency Rate is currently 0.14 injuries per 200,000 hours worked.
There were also no reportable environmental incidents during the quarter.
So it is now over 3 years since we had one.
During the quarter, our operations had some weather-related interruptions as is normal in Q1.
Per ton cost increased during the quarter due to the higher strip ratios we had previously discussed and the impact of lower shipments.
We continue to focus on maintaining the quality of our equipment and improving the deployment and effectiveness of our preventative maintenance and equipment monitoring programs.
At the Antelope Mine, we have began replacement of the tub of one of our draglines, which will take 2 months.
As the dragline downtime will reduce our stripping capacity, this has been time to coincide with the Q2 shoulder season when we typically have lower shipments.
I'll now hand over to <UNK> to cover the financials before I talk about the 2018 outlook.
Thank you, <UNK>.
Our consolidated adjusted EBITDA for the first quarter was $19.6 million as compared to the $20.4 million for the first quarter of 2017.
While the consolidated results are relatively consistent, a shift in the mix of earnings in the period occurred as improved logistics earnings and lower SG&A expense offset lower domestic earnings in the period.
During this first quarter of 2018, we shipped 12.3 million tons of coal.
This compares to our first quarter shipments in 2017 of 14.1 million tons.
The current-period volumes included 900,000 more tons of exports at higher margins as compared to prior year.
Our realized domestic price per ton of $12.20 for the first quarter is slightly higher than the $12.10 per ton reported for last year's first quarter, which primarily reflects the changing mix of our coal sales.
With the increasing strip ratios, higher diesel costs and the lower volume of shipments, our cost for the first quarter were $10.94 per ton.
Comparatively, the first quarter of 2017 cost per ton was a $9.87.
We forecast the magnitude of this comparative quarterly impact to decline throughout the year as the pace of shipments is expected to increase to achieve our guided volumes.
During the first quarter, our Owned and Operated Mines segment generated adjusted EBITDA of $18.6 million.
Export shipments for the first quarter of 2018 were 1.4 million tons, which is consistent with our rail and port contracts and is a significant improvement as compared to the ramp-up pace experienced in the comparable period.
With the steady pace in performance by the rail and port, efficiencies were gained, most notably, a $1.5 million lower demurrage charge in the period.
The logistics segment adjusted EBITDA was $7.1 million for the period, our best quarterly result since export shipments resumed in the first quarter of 2016.
With an average realized price of $57.13 per ton on our Asian export shipments, we achieved a $5.04 margin per ton, which is incremental to the domestic cash margin reported in our Owned and Operated Mines segment results.
The contracted and selling price for the second quarter is $2 to $3 per ton higher than the first quarter results.
We will benefit by approximately 50% of the increase as we incur higher rail rates in Montana severance taxes.
Our SG&A cost of $7.3 million were lower than the $11 million reported for the first quarter last year.
Overall, our SG&A costs were consistent with the prior year, except for our mark-to-market stock opposition expense that was updated for performance-based equity award.
As our stock price declined during the first quarter of this year, the calculation resulted in a $4.4 million credit to this estimated award value.
This mark-to-market volatility will continue throughout 2018 as these performance share units will vest in March 2019.
As we look forward, we are reaffirming our 2018 guidance.
Our range of shipments remains between 52 million and 56 million tons, of which we expect to export approximately 5.5 million tons.
Our 2018 adjusted EBITDA guidance range continues to be between $75 million and $100 million.
Our range for capital expenditures remains between $15 million and $25 million.
We ended the first quarter with $127.8 million of cash, which is an increase of nearly $20 million during the period.
While this amount will fluctuate throughout the year, particularly with the interest on our 2021 notes being paid in the second and fourth quarters, we continue to expect to grow cash on an annual basis.
Assuming we achieve the midpoint of our adjusted EBITDA guidance, the operating cash inflows would more than offset our forecasted capital expenditure and cash interest needs.
Our total available liquidity was $527.8 million at quarter-end, which is the aggregate amount of our cash balance plus available borrowing capacity on our undrawn $400 million credit agreement.
We are currently working to amend and extend our credit agreement, which matures in February 2019.
While we expect the replacement facility to be significantly smaller, our focus is on ensuring that we have adequate liquidity to support our business needs.
Our A/R securitization program was fully utilized throughout the first quarter to support the $23 million of outstanding collateral requirements on our reclamation surety bonds.
With that, I will hand the conversation back to <UNK>.
Thank you, <UNK>.
I will now cover the international and domestic outlooks before we take your questions.
The overall outlook for Asian seaborne thermal coal demand remains strong.
Chinese total electricity regeneration was up 10% in Q1 this year, largely supplied by coal.
Chinese imports in January and February were up 40% compared to last year.
Outside China, demand continues to grow as new power stations come online in Japan, South Korea and Vietnam.
We continue to experience strong interest in our ---+ from our Asian utility customers for our Spring Creek Mine coal.
Our Asian customers continue to seek the consistent quality and supply diversity our coal offers.
We have now contracted 3.3 million tons for delivery this year at improved prices.
With the rail and port system working as planned, we expect to ship 5.5 million tons.
The recent decrease in Newcastle and Indonesian thermal coal price indexes are common this time of year as the winter ends, and we expect prices to firm as the summer progresses and to be able to contract the remaining 2.2 million tons planned for delivery this year.
You may recall that last quarter we announced a new contract with JERA Trading to supply 2 new IGCC units that are currently being built near Fukushima Japan.
This contract had some flexibility to increase shipments.
We were recently notified by JERA Trading that they were exercising their option to increase shipments under the contract by 20%, bringing the annual maximum to 1.3 million tons after the initial ramp up.
We have seen increased interest from other Japanese utilities, who are keen to diversify supply and value the consistent quality our coal offers.
One successful test burn shipped in Q1 and another was recently contracted to ship in May.
We are also discussing test burns with other 2 Japanese utilities that could occur later this year.
On the domestic front, while the cold weather in January helped reduce coal inventories, the recent mild weather increased natural gas production, have allowed utilities to continue to hold off contracting.
Natural gas prices for May delivery are currently around $2.80, even with inventories 41% down on this time last year.
When utilities have issued RFPs recently, coal pricing had been very competitive as producers seek to fill their capacity.
We have currently contracted to sell 47 million tons this year, including the 3.3 million tons of exports.
This means we still have around 5 million tons of domestic sales to make to meet the midpoint of our production guidance range.
The 47 million tons of committed production are under fixed price contracts with a weighted average price of $12.28 per ton.
The 2 million tons we contracted or priced since our last call were at a weighted average price of $11.83 per ton, reflecting the mix of 8,800 Btu and 8,400 Btu coal and prevailing prices.
There was no change to our 2019 sale position since our last call, and we have contracted 24 million tons for delivery in 2019.
Of this committed production, 17 million tons are in the fixed price contracts with a weighted average price of $12.63.
So to sum up before we take your questions, as we come out of winter, we have seen a recent increase in the number of RFPs as utilities begin to contract for the remaining of 2018 deliveries.
Competition is fierce, keeping coal prices down, as increased natural gas production keeps prices below $3.
We expect gas prices and weather to continue to drive incremental domestic coal consumption going forward.
At the same time, the outlook for our export business continues to improve with strong demand and solid prices.
We are looking to take this opportunity to schedule test burns with new high-quality customers and to continue to build our long-term relationships to our existing export customers.
With that, we can take your questions.
<UNK>, <UNK>, I wanted to follow up a little bit on the industry comments that you shared in the introductory remarks.
You spoke of fierce competition.
Obviously, there's the usually dynamics with weather and gas.
But can we talk a little bit more about the structural issues, where do you see coal burn this year versus last year.
And then importantly, when it comes to retirements looking out to 2019 and 2020, what's on the horizon, and how does it impact the PRB.
Okay.
So I think, as we said in the remarks that there's clearly utilities have been holding off buying coal.
There's coal to be bought for the remainder of this year.
And at the moment, the utilities that have come out for pricing has not been that many and obviously, with PRB producers, such as ourselves, having excess capacity to fill in the second half of the year, as you can imagine, the pricing is very competitive.
So that's the dynamic at the moment.
I think if ---+ as stockpiles have come down a long way from last year, there is the potential with gas inventories lower.
So if there is an early start to summer and a strong hot summer, big cooling demand for ---+ that's big, a lot of burn of coal just as we saw in January, and that could bring the utilities into the market in a strong way.
The other side of that is if there's a very mild summer, then that would leave them with buying less, and that wouldn't be good for all producers.
So that's the dynamic we're in.
The reality is the industry has changed massively from where it was 5 or 6 years ago when utilities used to know what they were going to burn through their coal plants and would buy accordingly.
There is a lot more variability, which is what we're coming to terms with.
We're optimistic that the rapid rate of closures we've seen in the last couple of years is actually slowing down and that will actually give them some opportunity for the supply and demand to come into balance and give more sustainable margins to producers.
That's not occurred yet, but we're closer to being in that position than we were this time last year would be my estimation.
But equally, we have to recognize there is an awful lot of gas coming on.
How much is that's balanced by exports and the need to continue investing capital to keep that production going, will play out in the next year or 2 as those markets mature and the economy develops and exports develop.
But that's a ---+ we're in a very dynamic market and we've got to see how that occurs.
We are optimistic the rate of plant closures will actually slow.
And I think that would be a key thing, though, I think realistically, most utilities are ---+ have longer-term their plans to close plants.
But hopefully, it's not in there.
They have gone through this round of closures, and we've got a few years of stability.
That's a very comprehensive answer and I appreciate that.
Maybe just to hone in on the potential for retirements.
As it stands today, how many million tons will be impacted in both 2019 and 2020 from the PRB specifically.
I haven't got that number at my fingertips, <UNK>.
I think it's a lot less than the last few years.
But the big ---+ there is a factor there that it's worth recognizing, that even if you get some closures, it doesn't mean you can't burn a lot of coal in the existing plants because utilization rates have gone down.
So there is actually a fair bit of excess coal burn capacity even with maybe less actual plants than we have had.
I mean, obviously, closing plants isn't a good thing.
But it doesn't mean there isn't the ability to go up when demand rises in seasonality.
And I think that's the dynamic we're going to face going forward.
So I think the actuals ---+ the rate of closures, whilst it's not a good thing, it's actually the demand level for power and the price of gas that is really going to drive coal burn, and therefore, the amount of demand for our coal.
Well, <UNK>, if demand isn't there, if the customers don't come out for it, I think it's pretty clear, we won't sell it.
But yes, the pricing ---+ there comes a price where ---+ we're obviously very close to it, where you don't want to sell.
And we've seen, if you look at our business, the production has come down significantly in the last few years.
We're looking for some stability this year, but we're actually ---+ we're obviously being helped significantly by the exports, which you guys look at our domestic plant ---+ or the middle of our guidance range, domestic is down by several million tons, but we're able to balance that with the exports.
So yes, we'll ---+ we can only sell what customers want to buy and then, depending on how that ---+ how many of them want to buy it will drive the price ---+ the level of supply will help drive the price.
But yes, we can only sell what people will buy.
We believe the coal ---+ I mean, the real driver, if it's an extraordinary mild winter ---+ mild summer, that would be bad.
If it's a hot one, that would be great.
So if it's a normal summer, yes.
There is ---+ we do believe there is a significant amount of coal to be bought by the utilities.
They are still actually burning quite a bit of coal.
And for all the doom and gloom around coal, it's still roughly 30% of U.S. electricity.
It's still quite a lot.
And that actually means that we ---+ they do need to buy it and they need to burn it to keep the lights and the air-conditioners on.
So whilst it's a ---+ it's very dynamic and it's changing, we're still pretty active and several coal producers.
Okay.
So the main factors for us, I think, are pretty clear.
On ---+ you've got the international pricing on the remaining 2.2 million tons, and I'd see that as potential upside.
We've got a negative would be diesel price.
If that comes ---+ what comes through there.
And then the big one is domestic volumes and what price we ---+ so the amount of coal we sell and what price.
I mean, those are really the variables facing us at the moment.
And certainly, the domestic stuff in terms of demand and price, that we'll be able to see that play out with the demand and ---+ I mean, summer weather at the moment.
<UNK>, this is <UNK>.
We had offered that in that range, about $30 million from the logistics business.
So you take 5.5 million tons that we still feel confident with, you multiply that by the margin that we were reporting in the first quarter, that gives you the data points, that gets you to the upper 20s.
So ---+ and then we said ---+ so the $5 margins on 5.5 million tons, that's where we feel confident.
We've got the pricing in there as well.
And we've got contracted position for second quarter being $2 to $3 higher than what we reported for the first quarter.
So that gives you the data points that ---+ yes.
Okay.
Thanks, <UNK>.
As we said in the sort of prepared remarks in the release, the performance of the rail and port this year has been in line with our forecast.
We did the 1.4 million tons, which obviously, on a quarterly basis, is just where we need to be to get to 5.5 million tons.
And the system is working as planned.
So that's all good.
And especially in the first quarter, compared certainly to last year when we're trying to ramp it up and there was bad weather and it obviously was a problem then.
The main thing we see with these systems is once the rail and ports are sort of chugging along and you've got the ships coming and the trains all in motion, then it runs well.
But going up and down quickly can be a struggle and cause some operational issues.
So at the moment, we're very comfortable with the operation of the rail and port.
In terms of the longer-term ability to get capacity we will obviously be in discussions with Westshore and the railway to see if there's any opportunities to increase production if any space becomes available.
And we believe the demand is certainly there with our Asian customers.
But we will be very watchful of the level of take-or-pays that we take on because remember, it was only 2 years ago that they were a significant problem for us.
So we need to be cognizant of that.
But overall, yes, we see opportunities there and we're pleased with the way it's going at the moment.
Sure, yes, thanks for the question.
And certainly, the way we saw the winter was through December, it wasn't very cold, and burn was lower.
In January, when it was cold, obviously, a lot of gas went to domestic and commercial heating.
And coal burn was right up.
And I think the recent numbers that came out show that coal was well over 30% of American electricity in January.
Then it dropped off a bit in January and Feb ---+ I'm sorry, in February and March as the heating demand went down.
So look, it absolutely plays out.
If ---+ gas certainly, the winter, the gas is in demand, then utilities burn a lot of coal.
I think, as we've said before, as long as gas is over $2.50, then we seem to see that utilities are burning the coal, our coal they've taken.
And so that seems to be playing out.
At the moment, however, they do appear to be holding off pricing, because I think they're comfortable that there's enough coal and gas available to ---+ given their current stockpiles to see them through the summer and then they can always buy what they need going into the winter.
That's how it feels to us as we look at the way the market's developing.
So that does mean that if there is a big demand or gas nudges up a bit because of the exports or industrial demand, then there's the potential for it to swing up quite substantially.
And as we've said for a while, utilities haven't been ---+ there's been no squeeze on them for a while, so they seem to be comfortable that there's always lots of coal and gas available.
We're optimistic there will actually be some demands, they'll actually be caught out a little bit.
And remember why they want decent amounts of coal on their stockpiles.
But until that occurs, it's pretty easy to sit back and take whichever is most opportune and realistic in short notice.
And so our market, the whole business has changed and we're having to adapt to that.
And this is the reality where we are.
Well, I think, after that, just goes to the lack of pipeline infrastructure to get gas around the country.
So if the Northeast is very cold, the heating demand there means that local gas is available, the price shoots up.
But gas in other areas where there maybe is overproduction, not enough pipelines to get it out, obviously, is much lower.
So I think that just goes to tell you that there aren't enough pipelines and you get a very regional market.
Okay.
Well, thank you for taking the time to listen in and for your interest in Cloud Peak Energy.
Obviously, we'll look forward to updating you on progress during Q2 in July, when, hopefully, we'll have a ---+ obviously, we'll have more insight into how the summer is developing and the full year.
So we'll speak to you then.
Thank you.
