Mammoth Energy Services Inc (TUSK) 2016 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Mammoth Energy Services third quarter 2016 earnings conference call. At this time, all participants are in a listen-only mode. Later we will conduct a question and answer session and instructions will follow at that time. As a reminder, this conference call is being recorded.

I would now like to introduce your host for today's conference, Mr. Mark Layton, Mammoth Energy Services Chief Financial Officer. Sir, you may begin.

Good morning and welcome to Mammoth Energy Services' third quarter 2016 conference call. Today's call is being webcast, and a replay will be available on Mammoth Energy Services' website for seven days.

Joining me today is Arty Straehla, Chief Executive Officer. 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 S-1, recent current reports on Form 8-K, and other Securities and Exchange 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 reconciliation to the most directly comparable GAAP financial measures are included in our third quarter press release, which can be found on our website.

Now I'll turn the call over to Arty.

Thank you, Mark, and good morning, everyone. Let me start out by saying that I am very excited and pleased to be conducting the inaugural earnings call for Mammoth Energy Services. This is a very exciting time for Mammoth, with the completion of our IPO, the repayment of our debt, and the fortification of our balance sheet to support our company's growth, both organically and through acquisitions.

The Mammoth team has accomplished a lot in a short period of time, and continues to execute at every level of the organization. I'm very proud of this team and all that it has accomplished during what has arguably been one of the harshest periods for oilfield services. Our organization is focused on executional excellence and getting the job done safely and in a quality manner at every level of the organization.

Let's take a minute and talk about what has transpired over the third quarter and beyond. The industry has gone through a cleansing and will recover as a healthier business. We've seen the recovery start, most visibly with the rig count in the US increasing from the lows of 400 rigs at the end of Q2 to close at 570 rigs last week.

While the recovery in rigs is one metric of activity, we are keenly focused on wells completed and completion design in addition to rig efficiency, all of which has continued to increase throughout this downturn. The technological improvements to this industry have been truly remarkable.

The recovery in activity is notable, and TUSK has been a beneficiary of this increase in activity. We were able to have our best quarter this year in all four of our operating segments on an adjusted EBITDA basis. While year-over-year comparisons are less relevant, we are focused on sequential improvements.

Our largest segment, completions and productions, was able to increase margins through cost control. We saw increases in sand pricing, and activity in our logistics division continued to be a positive adjusted EBITDA contributor.

On an adjusted EBITDA basis, it was our best quarter since Q2 of 2015. Mammoth produced adjusted EBITDA of $17 million for the third quarter of 2016, up from $12.8 million in Q2 of 2016. In fact, the month of September was our best month on an adjusted EBITDA basis since May of 2015, driven by improved frack utilization, higher sand prices and volumes, as well as continued utilization of our remote accommodations business.

Consistent with our past practices of protecting our balance sheet, we applied this cash flow to pay down our debt to $72 million at the end of the third quarter from $82 million in the 6/30 quarter period. We subsequently paid off all of our remaining debt balance with a portion of the proceeds of the IPO, and as of November 7th we had $174.6 million in liquidity.

We now poised and ready to selectively expand the Mammoth portfolio. We're well positioned in the key areas of development in the North American, and envision broadening out our exposure by adding capacity and by filling in additional services that make sense to us.

Certainly, as we go into Q4 of 2016, many challenges are still facing us, given that the oilfield service companies -- there are very few oilfield service companies making money. Therefore, we are looking for green shoots. Pricing and utilization remain low. But despite weak spot market pricing, Mammoth continues to benefit from contractual agreements that provide us earnings visibility into the future.

Since this is the first time we are reporting our earnings, let me give you a broad overview of the performance of each of our segments and where Mammoth is going strategically.

Our completion and product segment, the largest of our four operating segments, continued to perform well. We were able to achieve a sequential improvement to adjusted EBITDA of $1.5 million from Q2 of 2016 to Q3 of 2016. In addition, we were able to reduce costs further within our coiled tubing operations. We are a very focused operation when it comes to cost reduction.

Some smaller division within this segment continue to face lower utilization and pricing, forcing us to work to reduce costs further through improved management of labor and repair and maintenance. Our 160,000 hydraulic horsepower pressure pumping in Ohio remains in solid condition and focused on supporting our customers.

During the quarter, we performed under our contract with Gulfport and set several records for the number of stages that we pumped Gulfport and, for a full week in July, averaged 9 stages per day for each contracted crew. These are internal achievements for our team that we're very proud of. We continue to work hard on efficiencies and strive to perform for our customers.

Our proppant segment increased volumes of brokered sand during the period and continued to fulfill its obligations under our long term contract with Gulfport. The segment remains active in fulfilling orders and brokering sand both from affiliated and unaffiliated entities.

Sand pricing remains challenged, although it appears to be -- there seems to be a modest recovery. We continue to envision continued substantial increases in demand across the unconventional space, which will consume much of the available low cost sand capacity. Customers are pumping record volumes of sand per foot today, and we wonder what will happen when sand is not practically given away.

We were pleased with our ability to produce positive adjusted EBITDA for the quarter. Looking forward, we are equally focused on frack logistics as we are on equity sand opportunities. We are looking -- we are vertically integrated in the northeast and envision maintaining that strategy as we expand to new regions.

We believe bottlenecks at or near the last mile are ahead as the completion business ramps back to pre-downturn status. We believe logistical issues such as transload facilities, railcars, and trucking will need to be dramatically improved to supply wells where the lateral lengths are getting longer and the sand concentricity in the longer laterals is continuing to rise.

The notion that the industry is shifting towards 3,000 pounds per lateral foot and testing levels in excess of that is remarkable. We are not sure which part of the sand and logistics supply chain tightens first, but we believe we will be prepared with the time comes.

Our contract land and directional drilling segment saw increased activity and utilization in Q3. We recovered from the lows of Q1 of 2016, where we were running one rig in the Permian Basin, to running five rigs for the entire month of September. We also have incorporated cuts in SG&A, as well as a reduction in hourly wages.

Some of these savings were offset by costs incurred to ramp back up and increased maintenance costs, as we brought rigs from a warm stack condition to running in Q3. Our rig moving operations had the best quarter since Q3 of 2015 on an adjusted EBITDA basis, reflecting their survival as others left the business, and the recovery in the rig count in the Permian Basin.

Our directional drilling operations increased utilization during the quarter, although pricing still remains very difficult. That said, reflecting some recovery, the segment had the best quarter since Q4 of 2015 from an adjusted EBITDA perspective.

Over the past 12 months, our directional drilling unit has begun to incorporate a low cost rotary steerable system into their service offering, primarily focused on a more economical solution through the lateral. They've been seeing positive customer feedback and growing more optimistic about the breadth of its application and differentiation of their product offering versus some of the larger, more expensive players.

While we don't think GE is buying Baker Hughes solely for their rotary steerable tool, it is certainly a key part of their strategy, as discussed on their recent call. The adoption of rotary steerable technology can reduce days on well significantly for the E&P operators, and we believe should be a competitive advantage for us going forward. This can represent another area of growth within a division that we recognize will remain challenged for an extended period of time because of overcapacity.

Our remote accommodations segment continues to outperform our expectations, and had its best quarter of the year on an adjusted EBITDA basis. Total room nights were approximately 65,400 during the quarter compared to 47,500 in Q2 of 2016. We were able to pull additional costs out of the unit, and did not impact our quality of our service.

That said, as we've described in past disclosures, this segment will face contract roll off risk into 2017 that will include lower utilization. As you would expect, our teams are diligently focused, scaling our costs to fit with lower occupancy and keeping its adjusted EBITDA positive, although the segment will provide a de minimis contribution in 2017.

As many of you recall, one of the uses of proceeds besides paying off debt, which we did, was to source growth opportunities for our business, both organically and via acquisition. Since going public, we've been inundated with opportunities in various forms, including teams that want to join the platform and smaller sponsored units that are seeking exits.

The bid/ask spread remains wide, but we expect to be active in our dialogues with many opportunities. Despite these opportunities, Mammoth was built from the ground up, which we believe remains the best way to expand if we are able to secure equipment at attractive prices.

We feel we have identified such an opportunity, and plan to move forward shortly on 75,000 hydraulic horsepower of new equipment and expect to take delivery by the middle of 2017. We expect that this capacity expansion will fuel additional growth in the second half of 2017 and all of 2018, and will be funded from cash on hand and cash flow.

We think that this is a very important opportunistic move for us strategically, as we see frack equipment getting tight in the future and believe our price for our services will return to pre 2016 levels. We look forward to a balanced portfolio expansion along with this expansion to our pressure pumping fleet, and look forward to remaining as integrated as possible within the completion and productions area.

With that, let me turn the call over to Mark to cover our financial and operational results. Mark?

Thanks, Arty. For the third quarter, revenues were $62.8 million. Revenues decreased compared to $86.2 million in the prior year due to lower industry activity levels, equipment utilization, and pricing for our services.

Operating loss for the quarter improved to $0.1 million compared to an operating loss of $7.2 million in the prior year. Our loss per share was $0.08 compared to loss per share of $0.15 in the prior year. Adjusted EBITDA for the third quarter of 2016 increased to $17 million compared to $11.6 million for the same period last year.

The cost of revenue decreased from $70.4 million in the third quarter of the prior year to $42.7 million in the current year, primarily due to lower activity coupled with lower labor related costs and lower repairs and maintenance expense. Cost of revenue as a percentage of revenue increased from 68% in the prior year to 82% in the current period due to lower activity levels and continued low pricing for our services.

Selling, general, and administrative expenses decreased from $4.2 million in the third quarter of the prior year to $3 million this year. The decrease resulted primarily from lower total employment costs due to headcount reductions. SG&A expenses as a percentage of revenues decreased from 4.9% last year to 4.8% this year.

Depreciation and amortization was $17.1 million during the third quarter of 2016 compared to $18 million in the prior year. The decrease resulted from minimal capital expenditures during the past two years.

Impairment of assets, $0.9 million in the third quarter of the prior year. No assets were impaired in the most recent quarter.

As of the end of the third quarter, Mammoth Energy's pressure pumping fleet totaled approximately 160,000 hydraulic horsepower, of which one-third is unmanned but available to work. While utilization improved in many markets, we've not yet placed any unmanned equipment back in service.

As of September 30, Mammoth Energy's total headcount was 511 compared to 485 as of June 30th, 2016.

Capital expenditures during the second quarter were $1.6 million. And Mammoth Energy's full year 2016 capital expenditures are currently projected to be approximately $5.2 million, exclusive of the acquisition of additional frack equipment currently under negotiation that Arty mentioned earlier.

We continue to remain focused on maintaining a strong balance sheet and ensuring our equipment is adequately maintained and ready to work.

With that, I'll turn it back over to Arty for some closing remarks.

Thanks, Mark. Let me summarize the call. As we have discussed several times, Mammoth continues to execute well. We are pleased to have brought the company public, paid off our debt, and continue to generate positive cash flow in a very challenging environment.

We've produced steady positive results in the third quarter and provided some underpinning to growth as we seek to add brand new equipment for deployment next year. We think that Mammoth is poised operationally and financially to grow at a very rapid pace.

We are heavily engaged in identifying the winning strategies for the next market upturn, with particular focus in the area of frack sand, transload facilities, cementing, and logistics.

Thank you very much for your time, and let's open it up for questions.

Thank you. (Operator instructions.) Jim Wicklund, Credit Suisse.

Hey, guys. This is actually Chas Foote on for Jim. Congrats on a great quarter.

Thank you.

I just wanted to dig a little bit in on the C&P business. Margins came in at about 33% at the EBITDA line. I'm wondering how sustainable that is moving forward. Does that have to do with some of the Gulfport deferrals from Q1? And any more color on that would be appreciated.

We certainly did benefit from a lift related to the deferrals outside of Q1. We also benefitted from some lower than normal repairs and maintenance, largely due to timing related to the overhauls of engines and transmissions and primary components of our equipment.

We think the margins are sustainable in the high 20%'s. We obviously received a bit of a lift in the Q3 results related to that deferral.

Let me go a little bit deeper and talk a little bit about the R&M, because R&M is a big aspect of -- one of the single biggest cost aspects that we do, that we have within our frack operations.

We have focused very, very intensely on our fluid ends. We focus on our operational aspects of it, of how we prime pumps, how we bring them online, and we've focused with our vendors. Mark and I visited several of our vendors during the second and third quarter, as we seek to get the right fluid end matches with the pumping intensity that we have in the Utica Shale.

So, we are working extremely hard on that, and some of that result is starting to bear out. We're seeing average hours go up on our fluid ends, and we saw a cost reduction in our R&M in Q3 compared to earlier quarters that we had.

Okay, great. That's very helpful. And then the third spread that's not active right now, have you guys started to think about when that could go back to work and where it could go back to work?

That spread is currently in the northeast. It's available in the Utica and Marcellus. We've seen an increase in inquiries related to the availability of that spread.

We've not staffed that spread at this time, and the reason we've not staffed that spread is we're waiting for the calendar to fill in a bit more prior to bringing on the staffing. The equipment is 100% ready condition, but we're looking for a little more visibility for a longer period of time on the frack calendar before we staff that spread.

Depending on how commodities move over the near term, we think that spread could go back to work as soon as Q1 of 2017.

Look, in addition to that, we talked about the 75,000 horsepower that we're going to bring on. We're going to take those fleets to somewhere in the south. Whether Texas or Oklahoma, we're going to go and seek a home for it where we think it will bring the best return on investment. And part of that equipment, quite honestly, will be moving from there to the basins that we are going to go to in the south.

So, we will fulfill our contractual obligations with Gulfport with the two spreads that we have under contract. And we are going to try to optimize the utilization of that equipment and also optimize the pricing where we can get the best operational aspects of everything.

Okay. Thanks a lot. And then just one more on that 75,000 horsepower. Is that coming -- are you buying that from another service company? Is that coming out of inventory from one of the suppliers? And then if --.

It's --.

Sorry, go ahead.

I'm sorry. It's brand new equipment coming from a supplier. We think this is the opportune time.

As we said on the road show repeatedly, that we think we saw and have looked at equipment that we can get for about 67% of what it would have cost new two years ago. We think it's an opportune time to buy new.

We've looked at a lot of the used equipment in the marketplace either through auctions or through refurb opportunities and/or acquisition opportunities. And we think, quite honestly, that there has been an awful lot of cannibalization and an awful lot of where equipment is in very, very bad shape.

We wanted to go new. We thought it was the opportune time to do it. And we are continuing to negotiate and move forward on that.

Okay, great. And then just the final one. Would you expect those -- I'm assuming that 75,000 is two spreads. Will those go to work, you think, before the third spread that's idle right now? Any chance of that, or is that more like --?

No.

A 2H 2017 event?

No, we think it's all together with the strategy. We'll have three additional spreads that -- depending on what basin we go.

If you go to the Eagle Ford, the pressures are much lighter. The number of pumps required on job are less. If you go to the STACK/SCOOP, you have to use -- the intensity of the equipment is higher in some over pressured areas. It's lower in some other areas.

So, we're looking at the opportunities to do that. But anywhere we go, we will be vertically integrated all the way back to the sand mine. We think that becomes an important part of the 2017 story, the logistical aspects, the sand, the load outs, the transloads, the rail, and mining aspects of it.

We think all that becomes a big part of the future, and we're going to have all that vertically integrated. So, not only are we looking at just adding equipment, we're actually looking at adding a whole business line in anywhere we go.

Okay. Thanks a lot, guys. I appreciate it.

Thank you.

Jason Wangler, Wunderlich Securities.

Hey, good morning, guys. Maybe kind of dovetailing on the previous couple questions, I think you mentioned, with the new equipment, getting that in mid 2017. Can you just talk about that timing? It seems like it's a little bit more than maybe I would have thought, but just maybe some color around that.

We think that equipment may be available as soon as 16 weeks out. The equipment is completely manufactured and available at the manufacturer. They need to add a few things to it for us to take delivery.

We're somewhat conservative in that mid 2017 estimate. As I mentioned, it may be available as soon as 16 weeks out.

Okay.

Yes. And it'll come -- obviously it'll come to us in pieces. They'll get five done at a time, and then another five and that type of thing as it comes forward, as typically it does. And then there is a lot of other equipment that we'll coordinate. When we talked about -- we look to be a contribution to our numbers in the back half of 2017 and put it into play.

Okay, that's helpful. And then as you look at the staffing load for the third crew and then that one as well, and obviously you just spoke about moving it south, how do you see as far as the timing of that once you are able to move it and get it into at least a basin? And from a staffing perspective, whether it's cost or timing, how long do you think and how much that would be to both mobilize and get that up and running for whenever that's going to be able to go back to work?

We're not seeing current staffing constraints, and part of the reason for that is due to the contracted nature of two of the spreads in the northeast. We're fortunate to backstop our utilization with those contracts, and that's helped maintain the staffing.

As we look to add staffing for the third fleet in the northeast and for incremental fleets, we certainly see labor as a constraint going forward. But we've got industry relationships, both through our existing companies that we've got in each one of the basins, as well as those contracts that I mentioned earlier that certainly help us recruit and maintain highly qualified staff.

Great. Thank you. I'll turn it back.

Thanks, Jason.

(Operator instructions.) David Anderson, Barclays.

Hey, good morning. It's Will Thompson sitting in for Dave. Maybe just to follow up on that line of questioning, did you mention the budget for that 75,000 horsepower?

We did not. We're currently in negotiations for the final price related to that 75,000 horsepower. We believe it's an opportunistic purchase, as Arty mentioned earlier. It's about $0.67 on the dollar compared to what a spread would have cost two years ago, but we don't have a final amount on that as the negotiations are ongoing.

And then how do -- you mentioned moving that capacity to the south. How do we think about, you touched on the labor aspect, maybe just the cost friction of going into a new market? I know you have other equipment capacity outside of pressure pumping in the Permian. But how do you think about -- when your peers talk about scale being a competitive advantage and you're moving kind of maybe one or two fleets down there, what does that mean for sort of the margin profile in the onset of that work?

Well, we think it creates opportunity because we're one of the few frack companies that is completely backwardly integrated all the way through sand. And we've talked a lot about sand being tight. And you see some of the reflection of that going forward with what's going on in the overall sand markets. We also think logistics gets tight.

So, we're taking every bit of that aspect of it into consideration as we go forward. As you well know, we have operations in the Eagle Ford. We have -- the STACK/SCOOP is our backyard. The Permian is -- we have our rig operations there.

So, we are currently doing the whole business outlook at it, not only look just at frack operations but look at having sand, rail capacity, having logistics, having trucking, having -- making sure that we have plenty of water in order to do the fracks. So, we're looking at it overall from every aspect.

And we're just not ready to disclose quite yet exactly where it's going, but we are doing our diligence. We want to go where we can make money. And that's the driving forces behind it.

And just to add real quickly to that, I think we look at scale, particularly as it relates to frack fleets, more in the lines of two to three fleets for a district as opposed to one to two.

Okay.

One of the things that we did as we went through and we did the road show discussions and all that, we talked an awful lot about our customers and we talked about the cross selling opportunities. And that'll be a determinant factor for this next fleet as well.

We are in constant discussions with several customers where we think these type of operations will get tight. And we will have a customer -- we will try to have customer pull in as we go through.

And maybe that's a good segue just on the sand business. You mentioned opportunities on the integration side where you think that some of the bottlenecks will be. Can you clarify on that? Help us -- I think there's a little confusion still on kind of what your sand business model is today and maybe your vision of what it will be maybe in the next 12 to 24 months.

Well, right now we're brokering sand through Muskie and handling the logistics aspect of it. Muskie, if you remember, has 307 railcars. An affiliated company by the name of Taylor is a sand mine in Taylor, Wisconsin that has a 700,000 ton per year capability, and it's an affiliated company that sells us sand.

We think that it's -- you go back to the intensity of the fracks that are going on, they're going from 1,500 to 1,800 pounds per lateral foot. We've heard them as much as 3,000 pounds per lateral foot because the EERs for the E&P companies are greatly improved with additional sand concentricity. We heard a Chesapeake well in the Haynesville being tested out with 50 million pounds, 5,000 pounds per lateral foot on a 10,000 foot lateral.

So, people are -- there's no doubt people are going to more sand, longer laterals. We think that that puts a strain on the entire ecosystem of the supply logistics of how you get sand there, all the way to -- we can talk about the Delaware. You've got one railroad track going down to the Delaware. You've got a little bit of a transload facility, but how are you going to transport that much sand to the Delaware Basin?

So, that's what we're trying to get ahead of, and we are negotiating. We had Greenbrier in our offices yesterday talking about leases, as leases run off and additional leases and saving money and that type of thing, and how can we do it more economically.

So, we are looking at the whole process as a whole supply chain. Frack is a part of -- a big part of that, of course, but so is sand logistics, so is transload, so is trucking. If you look at the amount of sand that would have to be trucked out of Midland/Odessa because there's not enough transload facilities, it's just -- it's incredible on a two land road going down from Midland/Odessa through Pecos and Kermit and Monahans.

It's just an incredible amount of logistic nightmare. And we think we can get ahead of that curve, and we think we can be ready for it. And we're a frack company that will not run out of sand.

That's helpful. And then just to follow up on that point, I mean, you mentioned sand -- an increase in sand prices. How does that impact the profitability of your brokering business today under kind of -- and I know part of that's under a supply contract with Gulfport.

It is. We see it as opportunity. When pricing gets back up to the $30.00 per ton, we'll open the Muskie facility back up. Meanwhile, we're running -- the Taylor facility is supplying us sand during this time period. And Taylor has the capacity to be expanded beyond the 700,000 tons without a great deal of investment.

So, we see the upcoming sand as a great opportunity. And let me be perfectly -- Taylor is just an affiliated company. It's not one that we have any agreements to acquire or anything like that.

And last one for me, if I can sneak another one in, just you guys during the road show talking about the pipeline of M&A opportunities. Can you just help us, how has that vision and what -- that opportunity set has evolved over time, or how should we think about -- I know you're adding the frack capacity, but what's kind of the next opportunity set you think is available?

Well, we talked on the road show about having, oh, 25 or 30 in the pipeline. That pipeline for us doubled when we got back. I think there were a lot of people -- from what we heard and the feedback we got, there was a lot of people that were impressed that we were able to get the company out, get public and go out and execute.

We want to -- obviously, it's got to be accretive for us as we go forward, and it's got to be something that's going to make us a great deal of money. And we don't always think traditionally with our acquisitions. So, I will tell you we have a number in the pipeline that we will execute as we go forward, and we're working very diligently on that.

We want to focus on the completion and production area with sand and frack because, again, as the upturn starts to come back, we think that's the area that tightens the most. So, we are very focused on M&A. We are very active going forward, and we will continue to be active.

We think we have a window, a period, where we can -- will be able to eventually use our stock, after the lockup period, as currency. And then we've got the balance sheet to fall on where it's cash positive, and a full revolver out there.

Well, that's great for color. Thank you very much, and congratulations on the public offering on an eventful day here in the news flow. So, thank you.

What else is going on besides our call (laughter)? Thank you. Thanks for the call.

Thank you very much.

Thank you. And I'm not showing any further questions, so I'll now turn the call back over to Arty Straehla for closing remarks.

Well, thanks, everybody. Again, we appreciate everybody being a part of the inaugural call on our earnings. And we thank everybody for your time, and good luck.

Ladies and gentlemen, this does conclude the program and you may now disconnect. Everyone have a great day.