Good day, ladies and gentlemen, and welcome to the Mammoth Energy Services First Quarter 2017 Earnings Conference Call. [Operator Instructions] As a reminder, this conference call is being recorded and will be available for replay on Mammoth Energy Services’ website. I would now like to introduce your host for today’s conference, Mr. Don Crist, Mammoth Energy Services Director of Investor Relations. Sir, you may begin.

Good morning and welcome to Mammoth Energy Services first quarter 2017 earnings conference call. Joining me on today’s call is Arty Straehla, Chief Executive Officer, and Mark Layton, Chief Financial Officer. Before I turn the call over to them, I would like to read our Safe Harbor statement. Some of our comments today may include forward-looking statements reflecting Mammoth Energy Services’ views about future events. These matters involve risks and uncertainties that could cause our actual results to materially differ from our forward-looking statements. These risks are discussed in Mammoth Energy Services’ Form 10-K, recent current reports on Form 8-K, and other Securities and Change Commission filings. We undertake no obligation to revise or update publicly any forward-looking statements for any reason. Our comments today may also include non-GAAP financial measures. Additional details and reconciliations to the most directly comparable GAAP financial measures are included in our first-quarter press release, which can be found on our website along with our first-quarter earnings presentation. Now I would like to turn the call over to Arty.

Thank you, Don, and good morning, everyone. If you turn to page 2 of our earnings presentation, I would like to walk you through some of the highlights of the first quarter of 2017. The first quarter of 2017 was another strong one for Mammoth as we staffed our third fleet in the Northeast and restarted our Muskie sand facility. Financially, we generated revenues of $74.4 million, a net loss of $4.9 million, and adjusted EBITDA of $11.1 million, resulting in an EBITDA margin of 15%, which was ahead of analyst expectations. The first quarter was a busy one for Mammoth. In late March, we announced several pending acquisitions, including Taylor Frac, Stingray Energy Services, Stingray cementing, which are owned by Wexford, Gulfport and Rhino Resources in exchange for 7 million shares of stock. In addition, we announced the pending acquisition of the assets of Chieftain Sand, which we plan to rename Piranha for $35.25 million. Combined, these transactions will broaden our service offering in the Northeast, as well as significantly backward integrate our completion business. Once the expansion of Taylor is complete later this year, Mammoth is expecting to have processing capacity of nearly 4 million tons of sand per year, which by our estimation will be roughly double our needs once all six of our pressure pumping fleets are operating. In addition, the acquisition of Piranha is strategic as it is located on the Union Pacific Railway with unit train access, which will provide us a complementary low cost solution to move sand into the Mid Continent and Texas markets. With that, I would like to turn the call over to Mark Layton to cover our financial performance before walking you through the performance of our individual divisions.

Thank you, Arty. I hope that all of you have had a chance to read our press release, so I will keep my financial comments brief and focus on certain highlights we feel are important. As you can see on slide 3, Mammoth had a strong first quarter of 2017 with revenues coming in at $74.4 million, up more than 115% from the prior year quarter. A mix of higher industry activity levels, some improved equipment utilization, and pricing for our services largely contributed to the higher revenue compared to the prior year quarter. Operating loss for the first quarter of 2017 was $7.6 million, which is an improvement of more than 60% when compared to the operating loss in the first quarter of the prior year of $19.1 million. On a per-share basis, the operating loss came in at $0.13 during the first quarter of 2017 as compared to a loss per share of $0.70 in the prior year quarter. Adjusted EBITDA for the first quarter of 2016 came in at $11.1 million, up significantly from EBITDA in the prior year loss of $1.6 million. Our adjusted EBITDA margin remains strong in the first quarter, coming in at 15%. As we discussed on our first, on our fourth-quarter and full-year conference call, startup costs related to the staffing of our third fleet and expansion into the Mid-Continent, we are expected to compress our margins slightly during the first quarter. We expect this compression to be short-lived and remain confident that our corporate EBITDA margins will return to the 18% to 22% range once all of our equipment currently on order begins working. Selling, general, and administrative expenses came in at $6.2 million in the first quarter of 2017 compared to $3.3 million in 2016. The increase resulted primarily from…

Thank you, Mark. Moving to Slide 5, you will see a snapshot of Stingray Pressure Pumping. Our expansion into the SCOOP/STACK has begun with the yard and transload secured. And as Mark stated earlier, a majority of the equipment ordered in November is now in our possession. We anticipate our fourth fleet to be fully operational and begin its first job on June 1 with a fifth fleet expected to begin operations in August. The sixth fleet remains on track for a Q4 startup likely in October. Our frac calendar in the Utica and Mid-Continent is fully booked into the fourth quarter. While our first job will be with Gulfport in the SCOOP, we have plans to work for several operators in the area and intend to operate these fleets in the spot market for the next several months. Discussions have begun with several operators on longer-term agreements for 2018. So far in 2017, the industry has added 217 land rigs, which in our opinion has created the need for an additional 79 high pressure pumping fleets or roughly 3.5 million horsepower. In total, we believe current industry demand is roughly 11 million to 12 million horsepower based on the current land rig and growing. When you compare this to the current estimated working capacity of roughly 11 million, you can see why we and our peers believe pricing continues to see upward pressure. Some industry analysts are projecting a rig count of between 1000 to 1100 rigs operated by the end of 2018. This would equate to the need for up to 18 million horsepower by late 2018. If this comes to bear, there could be a significant shortage of horsepower in the market. While these are just estimates, the inbound calls and discussions we are having with our…

[Operator Instructions] Our first question comes Praveen Narra of Raymond James. Please go ahead.

So really nice to hear about the work booked into Q4 for your fleets. I guess how do we think about how that pricing is negotiated and where you guys stand on the idea of contracts at this point for the pricing which we have seen?

Well, certainly we have, two of our three fleets that are operating today are under contract with Gulfport, and that continues through September 30, 2018, which gives us very, very clear visibility. The third fleet is operating and will be totally consumed up in the Northeast throughout the rest of this year. And we are open to looking at contracts, but part of our story has always been that we wanted to be available for the spot market when the spot market passed over the contracted prices. And I think this gives us a good opportunity with our additional fleets to play the spot market, which we think from the pricing that we’ve seen is continuing to go up.

Okay, perfect. And I guess given what happened to the old markets recently and I know it has happened very recently, I guess could you talk about the indications you are getting from customers, especially for the SCOOP/STACK stuff that, on their interest in going forward with activity at these levels or however they are indicating it to you?

We have seen no change, Praveen, on our customers outlooks and their drilling. As we talk to customers in the first quarter and customer conversations that we have had as of late, many of them are still holding their production or holding their leases with the productions still drilling. We see no decline in anybody’s desire to complete wells and look at some contracting of sand. Since the announcement of our additional sand capacities, we have entered into a lot of contractual discussions about taking a large part of that, and those discussions continue as late as today with some of our customers. So we’ve seen no, understand the oil is at $46, understand the natural gas injections that occurred today and was reported by the IA. But, at the end of the day, we see no change in our customers’ behaviors.

That’s great color. Thank you very much, guys.

Our next question comes from Jason Wangler of Wunderlich. Your line is open.

Arty, was just curious, you mentioned the longer time it’s taking for some of these frac stages and the more sand, can you maybe talk about how you see that affecting the equipment in terms of whether you need more horsepower on location and then, frankly, the useful life of it because it just seems like that could also be a factor as we look out a little bit further down the road?

Well, Jason, it’s a very good point. It gives you a requirement. The intensity of the frac gives you requirement for additional equipment on site. I can go back to the fracs that we had several years ago, and we have 12 to 15 pieces of equipment with the built-in redundancies there. Today we have 20 units on there and on some of the fracs, and sometimes they require more than that. The fracs are much more intense with the longer laterals. I saw an article this morning, and this is the DJ Basin, but it is pretty indicative of what the E&Ps are doing. Bill Barrett and Anadarko both announced that they were going to use higher sand concentrations per lateral foot because the increased well results offset the additional cost of the additional sand and the pumping. So we are seeing more and more customers that are doing that. And, in fact, we are seeing the intensity continue to go up to -- the old standard was 1300 pounds per lateral foot. We are seeing a lot of people move to 2000 to 2300 pounds per lateral foot.

Great. Thanks. And then on the drilling side, upgrading a couple rigs already, could you just kind of give us an idea of your inventory, if you will, of opportunities to do that with the remaining rigs you have? It seems like so far it’s been going very well.

It’s based on customer demand and what people are seeing. We’ve seen a lot of upgrades from 5000 psi fluid ins to 7500. We are seeing a lot more in the area of customers desiring walking packages and those type of things. So we are doing those things that our customers absolutely are requiring on rigs. We spent about $2 million in Q1 to put capital into it and to increase our efficiencies and increase our rigs. We have good line of sight on eight rigs now going to work sometime by July 1, including some of our verticals. Our vertical rigs have been on the sidelines. We are starting to see some demand for them and some increasing calls to do saltwater disposal wells out in the Permian.

Okay. Great. Thank you very much. I will turn it back.

Our next question comes from Daniel Burke of Johnson Rice. Your question please.

I was wondering if you guys could help me with one that is a bit more specific on the proppant side. Just kind of looking ahead here to Q2. And as you all highlighted, we will see a mix shift in terms of broker volumes going down and Muskie volumes rising. I would imagine, it is my impression Muskie volumes carry a bit more margin for you guys, but can you help me maybe better understand how to think about the progression of the proppant business in the short-term here just into Q2?

Well, we are still seeing increased pricing. We are seeing pricing today, and we are sold out for the next 60 days on all of our 40/70, and we are seeing pricing go to about $45 a ton on 40/70. And pricing is pretty firm on the other grades as well. So we are seeing it -- we are seeing the effects of the longer laterals and in fleet increased sand. And you are right. We are not going to be brokering as much sand in -- going forward as we continue to grow.

Okay. And remind me, what is your 40/70 yield at or coming through Muskie? What is your percent of sales that are in the 40/70 range?

The percentage of sales is about 75%, Daniel.

High volume?

Yes. The yield out of the cut at Muskie is low to mid 50s, 40/70.

Okay, helpful. And then maybe as a follow-up -- the second one, a little more broad based. But anything you can share since that auction process has been concluded in terms of any refined thoughts on costs to getting the facility back, reactivated, and performing the way you would like it to? And maybe as a related question, what is the sand sourcing strategy for the SCOOP/STACK here in the interim as you ramp up over the next couple of quarters?

I think first to answer your question about Piranha, we have not taken over operations there as we have not closed that acquisition of those assets yet. So it is preliminary to be able to make an assessment on Piranha. I think your second question was on the -- on sourcing sand for the SCOOP/STACK. We are able to get to the SCOOP/STACK from our existing facilities at Muskie, as well as through the pending Taylor acquisition. It’s not as cost effective as what we will see once the Piranha acquisition is closed, but we do have sand supply from our existing facilities, and we will be able to get sand in the SCOOP/STACK in the interim period.

And in addition to that, part of the things we look -- rushed over a little bit was we have secured transload facilities here in El Reno that gives us the opportunity to service both the SCOOP and the STACK pretty efficiently. In addition to that, we are -- we have trailers and sand trailers and trucks that are coming on board where we will have the full logistics questions filled out where we can -- we have the solutions for our customers to get it not only to Oklahoma, but we also get it from the transload to the wellbore.

Okay. Great. And then maybe one last quick one just to toss in. In terms of the -- the couple of upgraded rigs, give us a sense for a rate range? I would imagine those will be helpful to overall realized rate, but can you give us a range for what those two rigs might be deployed at?

Those two rigs are in line with what we are seeing. Some of our other rigs -- so mid-teens is the range at which the rigs are expected to go back to work.

Thank you. Our next question comes from David Anderson of Barclays. Your question please.

Arty, in your remarks, you had mentioned current frac pricing up about 25%, 30% of the trough. Then you made a comment about mid to high 20s% EBITDA. I was wondering -- I wasn’t exactly sure what you’re referencing to, if that is what your target was or where you think it’s going to. But kind of related to that, I’m curious about your views on new capacity. You painted a pretty bullish picture on overall market fundamentals and how it’s all going to be tightening. So are you starting to think about that after fleet six gets out there what we’re going to do here and how do you think about getting back to that EBITDA number? Is there a targeted EBITDA that you need in order to make that -- I guess to make the decision on seven plus from here?

Right now, as you say, we’ve got the commitment for six, and certainly we are always evaluating markets and we are evaluating our customers’ behaviors and our customer demand on whether we will go forward with the next one or when we will go forward with the next one. To really put your question in perspective, we are quite bullish. We think that the full effect of the rig count, look, the rig count is up to 870 as of last week. And that full has been rising steadily through Q1 and will continue to, those wells that have been drilled will continue to be, needed to be completed. So we think that there is not enough horsepower coming on fast enough to offset what we think we will be able to do. So, to answer your questions about the EBITDA margins, when we talk about being up 25% to 30%, that is off our loads. And remember, one of the things that we talked about is we never took negative EBITDA work during the worst parts of the trough, so we are taking you from there. Now let me, one of the things that we always talked about, David, was that when we were going to be able to go from two fleets to three fleets in the Northeast, we had all of our equipment in good shape, and that is in attribute to our PM programs to having it already. We didn’t cannibalize during the downturn. So we, pretty seamlessly, with the exception of labor costs that we brought on, we had taken care of our equipment, and we were able to bring it up seamlessly to us. It did cost us about $750,000 to $800,000 in the quarter because we brought the crews on to get them trained in our methods and get them trained in our standard operating procedures.

As you are thinking and as you’re going through the process of bringing on this new acquired equipment out there, can you talk a little bit about the supply chain you are seeing? You had already talked about the labor, so I’m curious about everything else. Flow iron and all the other ancillary equipment around that, are their leadtimes starting to build out in any of this equipment? Are you getting kind of concerned about it? And also, I guess also similarly, as you think a little bit further out, what about engines and some of the bigger stuff? I’m hearing kind of contradicting data points. Some are saying there is long leadtimes, others saying there is not. Curious your take on that as you evaluate the market.

As we evaluate the market, some of the leadtimes for high pressure iron are extending out a little bit. On fluid ends, there was a bit of a pinch earlier this year where we monitor that supply chain pretty closely with our suppliers. We are not seeing any bottlenecks that would prevent us from rolling out the equipment in the timelines that we outlined in the prepared remarks, but there are some delays appearing inside of the supply chain. Specifically as it relates to engines, that timeline is extending out. I think we made comments previously in regards to the supply of cat engines. We monitored that fairly closely prior to our order of 58,000 horsepower earlier this year. We expect that timeline to continue to extend as more orders are placed.

Okay. Thank you. And one last quick question. I was just going through your slide deck there, and I saw the timing of Chieftain coming in there. I had a startup in early 2018, but maybe I was just being more conservative. Was there a change there? Does that get slit up in your numbers there, or was it just me being conservative in my model?

I think you have got a fairly conservative model. We have been somewhat conservative in our timeline since we have enclosed that transaction and haven’t taken possession of those assets. But I think the short answer is you are fairly conservative in your model.

[Operator Instructions] Our next question comes from John Daniel of Simmons & Company. Your line is open.

Just a few quick ones for me. First, housekeeping I guess. You noted you are drilling some saltwater disposal wells. Is that for service companies or E&Ps?

It’s for E&Ps.

Okay. Got it. Thank you. And then a number of companies like yourselves are reporting full frac calendars. I’m curious given the tightness now, when you book stuff, have you taken any type of deposits, and just curious if there is any risk that your customers are double booking dates, if you will, thus potentially leading to a possible overstatement of demand?

Traditionally, it’s not, we have not seen this business where you put down deposits to secure that date, and we are not doing that, John. We haven’t got to that point. Does that potential lie there? Yes, it could perhaps, but we haven’t seen it so far. And in the Northeast, we are very sure that one being pulled through Q4.

Okay. Then just sort of last one. Obviously you guys have a strong balance sheet, and you’ve made some nice tactical tuck-ins and we are certainly opportunistic on the capital equipment expansion early, but you guys have been doing this a long time. And we can’t be dismissive of $46 oil, particularly given it’s not clear where we are going from here. So just I know with that uncertainty, is the appropriate step at this point to maybe dial back further capital expansion plans that you can leverage your balance sheet, perhaps make some pretty big or bold strategic moves should oil prices migrate lower?

We monitor the commodities very closely, and we are cognizant of the macro. We are nimble and able to adjust our CapEx budget. So to your point, we will continue to maintain a conservative balance sheet, we will continue to be opportunistic with the deployment of capital, and we will be nimble in regards to our CapEx program.

Okay, great. Just would you say your preference from this point forward would be more towards acquisitions versus organic CapEx purchases or the opposite?

I will tell you, John, no, our story remains the same. It’s an organic growth and look at all acquisition possibilities, and when you get the right ones and if the right deals came around on equipment and that type of thing, we would certainly look at executing. We are very cognizant of where the commodity pricing is and we look at that, but we are totally focused on executing. We are totally focused on digesting the acquisitions that we’ve just done in Q1. We are meeting every week on our expansion on Taylor. We are meeting and discussing, and as soon as we fund and close Chieftain on what our steps are going to be to get there. So we are totally focused on execution.

Okay. Awesome. Thanks, guys.

Thank you. At this time, I would like to turn the call over to Arty Straehla for any closing remarks. Sir?

Well, thank you. Certainly appreciate everybody’s time and taking part in certainly the discussions that we’ve had. This really concludes the call. We will certainly be available to discuss and to talk with the analysts at any point in time. One of the things I would just like to -- this concludes a busy, busy first quarter for us. With all the acquisitions that were announced, all the things that we are bringing in, but we still think strategically we are in the right position and on a go forward basis. We moved our sand capacity to 4 million tons. We’re going to need about 2 million of that to operate for ourselves on what we see right now, and we will be taking opportunities to contract out sand as we go forward and to look at it. We think there is more upside on our rig site to -- as it gets fully deployed, and we feel very comfortable with where we are at this point in time and we will -- again, and I will reiterate what I said to John about the focus on execution and making sure that that stays there. We know about -- we are watching the commodity prices, we are watching a lot of other indicators, but we are totally focused on executing. With that, I will turn it back over to the operator and say goodbye.

Thank you, sir. And thank you, ladies and gentlemen for your participation. That does conclude Mammoth Energy Solutions call. You may disconnect your lines at this time.