Mammoth Energy Services Inc (TUSK) 2018 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Mammoth Energy Services Third Quarter 2018 Earnings Conference Call. (Operator Instructions) As a reminder, this conference call is being recorded and will be available for replay on the 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 Third Quarter 2018 Earnings Conference Call. Joining me on today's call are Arty Straehla, Chief Executive Officer; and Mark Layton, Chief Financial Officer.

Before I turn the call over to them, I'd 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, Forms 10-Q and 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 reconciliations to the most directly comparable GAAP financial measures are included in our third quarter press release, which can be found on our website along with our updated presentation.

Now I'd like to turn the call over to Arty.

Thank you, Don, and good morning, everyone. The third quarter of 2018 marks 2 years as a public company for Mammoth and a quarter in which we reported record net income of $70 million, or $1.54 per share, 45% higher than consensus estimates.

We were able to generate reported adjusted EBITDA of $184 million or a comparable EBITDA of $114 million, excluding the reversal of bad debt expense, versus consensus estimates of $110 million on $384 million of revenue.

While Mark will elaborate further -- elaborate further on our financial performance in his comments, I wanted to point out a few key highlights. Cobra continues to perform exceptionally well. Similarly, our oilfield service teams excelled and, despite the current softness in the market, maintained utilization during the period.

From a portfolio perspective, our third quarter results again underscore our differentiation from many of the oilfield services companies we are compared to. Following our rapid oilfield expansion in 2017, we deliberately chose to transition our asset base from a pure oilfield service company to a diversified industrial company. We are attracted to the reduced cyclicality, stable cash flows and contracted nature into which we feel we can effectively deploy our cash flow.

This transition to an industrial company can clearly be seen in our financial results with 64% of our revenues over the past 12 months coming from our Infrastructure segment. Our M&A focus remains on the industrial side of our business, which should push the percentage of industrial revenues even higher, if we are able to find attractive opportunities.

We remain acquisition-focused and are currently evaluating approximately 25 transactions, some of which provide services that are in high demand due to bottlenecks in the current oilfield and infrastructure service space, and are expected to have rapid paybacks.

In addition, we are evaluating several opportunities that tie to our interest to further expand our industrial presence and could provide stable cash flows in the years to come.

As our history has shown, we intend to remain disciplined in the deployment of capital, choosing only the transactions that are projected to meet or exceed our hurdle rates.

Now let me give you an update on our current operations, starting with the Infrastructure division. The Infrastructure division continues to perform at a high level in all of our reporting areas and exceed our expectations. Our team has been in Puerto Rico for just about a year and continues to work closely with PREPA and other governmental agencies to improve the resiliency of the energy infrastructure network in Puerto Rico. The task of reconstructing parts of the electrical grid to both harden it and provide better protection from future storms has begun. While the power has been restored to the island, the fragility of the system remains.

As we have stated in the past, the reconstruction process in Puerto Rico is just beginning with significant front-end engineering required prior to reconstruction of the electrical utility grid. As PREPA plan shows, we anticipate a ramp-up in reconstruction projects through 2019, with work to continue for the next 5 to 7 years. Staffing levels in Puerto Rico have fluctuated between 500 and 600 people over the past 60 days.

In the Continental United States, our teams have been actively working for multiple investor-owned utilities, and responded to the call for mutual aid following Hurricane Florence on the eastern seaboard and Hurricane Michael on the Gulf Coast.

We remain in discussions with several large investor-owned utilities to expand our operating footprint and build our backlog in all of our operating areas. The Infrastructure division's total backlog was approximately $1.2 billion at the end of the third quarter.

The breakdown of the backlog includes approximately $700 million remaining in Puerto Rico associated with the existing contract, and approximately $520 million in the Continental United States. We continue to work in the Northeast, Southwest and Midwest portions of the United States and in Puerto Rico for private, public, investor-owned and cooperative utilities.

From an oilfield service perspective, in the -- the third quarter was challenging with E&P budget exhaustion leading to some weakness in both pressure pumping and sand demand late in the quarter. Discussions with existing and potential pressure pumping customers are ongoing, with demand expected to pick up in early 2019 once E&P budgets are reset. We pumped 1,594 stages during the third quarter of 2018 with our EBITDA margins for our pressure pumping division coming in at approximately 17%. We currently have 3 of our fleets in the Northeast and 3 in the Mid-Continent.

Turning to sand, due to weakness in the -- in pricing late in the third quarter, we elected to temporarily idle Muskie, which is a higher cost facility. Our Taylor and Piranha facilities remain active. The team has worked very hard at -- on efficiencies at both Piranha and Taylor, with production costs falling faster than originally forecast. When operating at full capacity, these mines have production costs in the $10 to $12 per ton range, which puts them in the top quintile of the industry.

We sold approximately 600,000 tons of sand during the third quarter of 2018, of which 17% was brokered. The average sales price for sand sold during the third quarter of 2018 was $37.88 per ton.

Our blended third quarter production costs came in at approximately $14.50 per ton, in line with our projections, allowing us to support EBITDA per ton of just over $23. The temporary idling of our Muskie facility is expected to reduce our average production costs by 5% when compared to our third quarter production costs, to approximately $13.75 per ton during the fourth quarter of 2018.

As a reminder, we reserve approximately half of our 4.4 million tons per annum processing capacity, to ensure that our pressure pumping companies do not run out of sand. We have another 1.3 million tons, or 30%, under long-term take-or-pay contracts across multiple grades. 2 of the 3 contracts in place are 3-year take-or-pay agreements which run through late 2020; the third contract, which we recently renewed with Gulfport Energy, runs through 2021.

The crude transportation business, which we acquired during the second quarter, has seen strong demand, with 44 trucks in the fleet today, which is more than double from where we started. Inbound calls from both existing and new customers remained strong and we anticipate growing our crude logistics business throughout the end of the year.

Before passing the call to Mark, let me sum up Mammoth's transition over the past years in this way: the transition that Mammoth has undergone over the past year to shift to a broader industrial focus has been delivered, which can clearly be seen in our financial results.

Today, we have a debt-free balance sheet and free cash flow expectations for the remainder of 2018 and throughout 2019. Given our acquisitive nature in areas that further our transition away from the highly cyclical oilfield sector, we expect a further differentiation in the future. We will remain disciplined, patient and exclusively focused on opportunities that meet or exceed our targeted thresholds.

Let me turn the call over to Mark to take you through the financial performance during the third quarter of 2018, after which we will take questions.

Thank you, Arty, and good morning, everyone. 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.

Mammoth's revenue during the third quarter of 2018 came in at $384 million, down 34% from the second quarter of 2018. A reduction of activity in Puerto Rico in our Infrastructure segment and a slowdown in the oilfield completions market contributed to the lower revenue compared to the prior period.

Net income for the third quarter of 2018 came in at $70 million, up 62% from the second quarter of 2018. On a per share basis, net income came in at $1.54 per share. Increased focus on cost and reversal of amounts previously reserved as bad debt expense contributed to the increase compared to the prior period.

Adjusted EBITDA for the third quarter of 2018 came in at $184 million, up approximately 24% from the second quarter of 2018. Excluding the reversal of bad debt expense, EBITDA came in at $114 million, which was directly comparable to consensus estimates of $110 million.

Our corporate adjusted EBITDA margin was 48% during the third quarter, or 30% excluding the bad debt expense reversal, as compared to 28% in the second quarter of 2018.

Selling, general and administrative expenses adjusted for the reversal of bad debt expense and equity-based compensation came in at $23 million, or 6% of revenues during third quarter of 2018, and $20 million in the second quarter of 2018.

CapEx during the third quarter of 2018 was approximately $41 million, the majority of which was related to the organic growth of our Infrastructure segment in the Continental United States and the expansion of our trucking and rental fleet in the Mid-Continent region. Our 2018 CapEx plan remains at $205 million. At this time, we project our CapEx to be fully funded through internally generated cash flows.

On October 17, 2018, Mammoth entered into an amended and restated 5-year, $185 million credit facility. This credit facility amended our existing $170 million credit facility, which was set to expire in late 2019.

As of September 30, 2018, we had no borrowings under our credit facility and it remains completely undrawn today. Based on our current CapEx budget and cash flow outlook, we anticipate building cash throughout the balance of 2018.

On October 29, 2018, our Board of Directors declared a quarterly cash dividend of $0.125 per share of common stock to be paid on November 15, 2018, to stockholders of record as of the close of business on November 8, 2018. This dividend reinforces our commitment to a balanced shareholder return. We thank our shareholders for their support.

This concludes our prepared remarks, and we thank you for your time and attention. We will now open the call for questions.

(Operator Instructions) Your first question comes from the line of Tommy Moll from Stephens.

Arty, I wanted to start on Puerto Rico. You mentioned in recent weeks and months, the head count down there has been in the 500 to 600 range. Is that the right range for us to think about for the fourth quarter? And can you give us any visibility on the pace of -- the pace and the magnitude of the ramp in head count as we get into next year?

For those of us who are a little bit less familiar with the process, if you could give any context on the front-end engineering piece, that would be helpful as well, and also any visibility to when the next RFP process might kick off?

Sure, Tommy. We'll certainly address that. Let me say that the front-end engineering is probably the long pole in the tent of getting that done for the reconstruction aspect of the business. We -- as we stated in our press release, we're between 500 and 600 people. We think additional RFPs will be let as that plan starts to come, probably in the first quarter.

We have good visibility of the $900 million reconstruction contract that was signed in May 29 to go through that year and then we think additional bids will be coming early in Q1 -- early to mid-Q1, as engineering starts to get done. So we look for the ramp to probably follow that.

We probably will stay pretty stable with our head count right now for your modeling purposes, between 500 and 600 people, and then we would see a specific ramp as more projects become well defined by -- obviously, this a partnership between us and PREPA and we're both working hard to it. We have an engineering group down there that is working, and we are trying to get those projects approved as quickly as possible.

Okay. Thank you, Arty. One on sand. Obviously, there have been some macro headwinds pressuring that business -- yours as well as everyone else's -- in the recent months. One of the positive items for you guys has been the ability to cut costs even faster than expected. Can you walk us through how you're responding to the challenges in that business and, specifically on the cost side, what some of the levers have been there?

Sure. Tommy, when we first saw the marketing starting to soften a little bit, we pulled back our high-cost facility. We temporarily shut it down for a period of time until we see the rebound in activity. So that -- as we said in the prepared notes, that took about 5% off our cost structure, because it was a higher-cost facility.

So the team has done an excellent job of reducing their cost, putting some lean manufacturing-type techniques in place that take costs out of the overall system, and we've got a very effective management team that addresses this.

When we do come back, which we are starting to see signs now that prefills will start happening later in the fourth quarter and starting to see some of that starting to bounce back. When we ramp up to full production, we'll have world-class numbers in the $10 to $11 at both Piranha and Taylor.

We also think that we can be better than that; challenged our team get into the $8.50, $9.00 range, and what would it take to do that. And in fact, we have hit that in some separate months, not for an entire quarter, at both Piranha and Taylor.

Your next question comes from the line of James Wicklund from Crédit Suisse.

You talk, Arty, about you're becoming a diversified industrial company and you're transitioning to industrial and you noticed -- note 64% of revenues on a trailing basis this quarter were from Infrastructure. How does one actually go about changing from one type of company to another? I mean, what do you guys have to do to change your SIC code or whatever, so that you actually fall in benchmarks that industrial portfolio managers look at, rather than just, or in addition to, what oilfield service portfolio managers are benchmarking?

Yes. That's -- very, very interesting question on how we make that transition, and Don Crist has worked extremely hard -- that was one of the things that we had discussed early in the second quarter and we've been working with MSCI to get that changed.

Our trailing 12 months -- you have to have revenues that are over 60% and attributed to that particular industry, and we've done that. And we are actively engaged in calling them. How quick that process will take, we're dependent on other people for that, so we don't know the -- how expedited it will be, but we are making that attempt to change our GICS code to -- our General Industrial code, to an overall industrial company.

Well, you're my best-performing oilfield service stock for the last 2 years, so I really don't want to see you go. But I understand the drive, I got it, I got it.

On your 25 potential deals that you're looking at, you noted that you would probably be growing your infrastructure business faster than you would be growing your oilfield service business. And so I assume that 25 is somewhat of a mix of both. We've seen an awful lot of deals done lately, small private companies that don't have the mass to go public on their own get acquired.

Can you talk a little bit about the size and the scope and probability of some of these acquisitions, not what they do, because you can't do that, but can you talk about just what they are from a size, scope and all capability, and the likelihood that something gets done?

Well, it's -- I mean, you've been following our model, as you said, for a couple of years. One of the aspects we like is the vertical integration aspect of it, so we certainly do different things in that arena.

We do still look at a multitude of -- between oilfield services, between the infrastructure business and between the other industrials. And we really like the model that was much like Cobra, where it was a very small platform acquisition that we were able to put some capital to and grow. We don't pay -- like to pay a lot of blue sky. So that kind of generalizes it.

We are working very hard. We've always kept a number of acquisitions. Is there anything imminent that I can talk about? No, but we are very acquisitive, and with the balance sheet we have and the cash flow that we have -- see the future, we think it bodes very well for adding on and bolting onto our platform.

Your next question comes from the line of Daniel Burke from Johnson Rice.

Wanted to touch on U.S. infrastructure. Backlog looked pretty stable quarter-over-quarter, but maybe just remind me, you guys have about a $100 million CapEx budget for Infrastructure writ large this year. What's the U.S./Puerto Rico split there, and how are those dollars being deployed into the U.S. side?

You're correct, Daniel. For the year, we allocated approximately $100 million to the Infrastructure segment. Year-to-date, we've spent just under $80 million. Approximately $35 million of that $100 million is allocable to Puerto Rico, the rest is to grow the lower 48 inside of the Infrastructure segment.

Okay, and that's -- is there a way to think about that in terms of crew counts or truck counts, in terms of how much more capacity you're fielding today than, say, a year ago at this time?

It's approximately 125 crews for the year that we'll be adding in the lower 48.

Okay. Can you give me a crew count at present?

At present we've got just over 100 distribution crews and right at 5 transmission crews.

That's just in the U.S., Daniel. That's not counting Puerto Rico.

No, that's what I was looking for. That's helpful. And any -- you guys have alluded to pursuing some potentially sizable awards on the U.S. infrastructure side. I mean, any more clarity you can lend about the time line to look for such awards?

We've been working this aspect hard; we've probably got about $2.2 billion right now of bids outstanding. The awards line up with the IOUs and with their CapEx and that type of thing. But we have been aggressively pursuing a whole lot of bids and we think some of those will come to fruition in the near future.

Okay. And then, I guess, to switch gears, on the pumping side, I mean, the market feels like it's willing to kind of look through, at this point, the chop we're seeing out there. But it looks like there's been a little bit of shuffling in your fleet. I think you guys were in the Permian earlier this year, doesn't sound like you are right now. How are you navigating the market presently in pumping? And what are the indications of demand you have looking forward to 2019?

Arty and I have both spent a lot of time speaking with customers. Q4 compared to Q3, we see similar utilization. On average we ran 3.5 fleets inside of Q3, implying an annualized EBITDA for those fleets of about $17.7 million. As the E&P companies reload their budgets in Q1, we're seeing strong demand across multiple basins.

Daniel, I'd add to that that most of our conversations are around budget exhaustion, with the customers that we've spoken to, and most of them are really being pretty aggressive as we get into early parts of 2019. We think our utilization will go well beyond the 3.5 spreads as early as January -- early January.

Okay. And Mark, just as a point of clarity then, if you're expecting similar utilization in pumping from Q3 to Q4, should we look for sort of similar adjusted EBITDA performance from that business in Q4? Or do we have to lay on top of that any type of incremental pricing pressure?

No, we expect to be in the same ZIP Code for Q4, based on the visibility that we've got on the schedule today.

Your next question comes from the line of Jason Wangler from Imperial Capital.

I wanted -- you kind of hit on it a little bit there, Mark, but curious -- and you as well, Arty -- as you think about the spending into 2019, and obviously I know you haven't put out specific guidance, but would it be fair to assume that the budget for CapEx would be relatively similar to this year and allocated in a similar fashion? Or should we thinking about it in a different way?

Jason, I think as we look at 2019, we're reviewing our CapEx plans. I think the one thing that we're certain about is we'll stay within free cash flow. In regards to allocation, I think it looks pretty similar to the split we saw in 2018. We're very interested in continuing the shift to industrial focus, so would expect a very similar split in '19 as compared to '18.

And I would add to that, Jason, that some of the bids that we've put in would require additional CapEx that -- if we got those. So we're interested in growing that business. That's going to continue to be, and the industrialization of Mammoth is going to continue.

Sure, okay. And kind of on that, Arty, but kind of differently, in your prepared remarks you talked about the investment in the trucking side of it on the oil and gas side had been still pretty busy, and the things I've heard, it's still obviously in high demand. It's not one of the things that's been slowing down. Can you talk about kind of the growth profile you see there and do you intend to kind of continue investing in that business going forward?

Yes, we invested a fairly modest amount in, first of all, the purchase of WTL, our crude hauling. We had seen the pipeline capacity issues starting to come to fruition somewhat in Q1. We made the acquisition in Q2. We started with 20 trucks and we are -- we have a total of 44 now that we continue to grow.

We see very good margins and increased pricing on, especially, the Texas routes, that -- we pull oil from Owens Lake, just outside the Permian, to Gardendale, that is southwest of San Antonio. So those are nice long runs of transporting crude and very profitable for us. So we are actually continuing to add trained people and add people to that and we effectively had about 28 trucks running in the month of October and we continue to climb to get to that 44.

Your next question comes from the line of Praveen Narra from Raymond James.

I guess, I just wanted to start on a follow-up for Daniel's question on the U.S. infrastructure business. There's obviously a lot of bidding going on. Can you talk about how the mix is on time and materials versus project-oriented stuff for the projects that you are bidding on?

It's heavily slanted towards time and materials right now. The team is bidding a substantive amount of project-based work. But for what we've seen through the first 9 months of '18, it's heavily driven by the time and materials projects.

Okay, perfect. That's good to hear. And then I guess, going back to Puerto Rico, I just want to make sure I understood the answers to Tommy's question. So in terms of the cadence, I guess, right now, it sounds like most of the crews, or virtually all the crews, are doing restoration work under that -- under that contract scope.

As we get into Q1 and the engineering design phase is done, will we be able to keep the same number of crews working just doing restoration up until that time, and then those guys can switch over to reconstruction? Or I guess, can you give us kind of an idea of how much restoration work is left to be done under that contract?

There's about 15% of the island that is remaining to be energized. All of the meters are energized, but there are about 15% of the lines that remain, relative to the restoration piece of the project in Puerto Rico.

Okay. So I guess then, in terms of the margins, 3Q's margins were -- even excluding the bad debt reversal, were phenomenal in the Infrastructure business. Can you talk about how we should think about that? I guess, I'd always thought of it as a mid-20s margin for Puerto Rico. Can we talk about how the margin increased so high, and what we -- how we should think about that, going forward to 2019?

Well, Praveen, one of the things you know about background is that we are cost-focused and we try to take cost out of any system that we're working within. We've been on the island for about a year now, and you learn how to do things more efficiently. You learn how to take care of feeding people and housing people, and at a lower cost than what we -- when we originally went.

And quite honestly, we do some -- we take on some more of the work that -- and reduce the subcontractors -- some of the subcontractors that we have. So that's why you see a little bit of our margins staying relatively strong through this.

We think -- we've always said, and I'll take you back to December of last year, our contract was found to be in compliance and our rates were fair and reasonable. And we continue to operate under that. We try to operate very, very efficiently and try to make sure that we are bringing the power back to the people of Puerto Rico.

Okay, and if I can ask one clarification question on the sand one. How much of the sand in 3Q that was sold was used for internal purposes?

Internally, we used, round numbers, about 200,000 tons internally.

(Operator Instructions) Our next question comes from the line of Taylor Zurcher from Tudor, Pickering, Holt.

Most of my questions have been answered. I did just want to clarify or follow on to Praveen's question about margins in Puerto Rico, and it's obviously good to see the cost structure coming down. But just to clarify, are the -- is the cost structure there moving forward, as the head count fluctuates or kind of stays in the 500 or 600 range near-term?

I mean, is the cost structure at a point where the margin performance, excluding the bad debt provision or reversal, is something you can maintain, at least in the near term, or is that still sort of a moving target?

I think it's something we can maintain in the near term. The one caveat is that is somewhat driven by mix between transmission and distribution work. So there will be a little bit of lumpiness in that, but it's not a large amount of lumpiness as we shift the distribution mix.

Okay, great. And then on the sand side, I guess, challenges facing that segment are pretty well known. My question is, just given the volume decline sequentially, a lot of your sand's contracted and I'm just curious how the contracts are holding up. I mean, did you see any volume pressure from the contracted piece, or was that primarily weighted towards most of your spot volumes?

As we look at Q3, it's mostly weighted to the spot volumes. Our contracted customers, in large part, pulled the volumes under contract. But those are long-term partnerships with our customers and they've continued to pull sand throughout Q3 and into Q4.

Okay, and I'll sneak one more in, just borne out of curiosity. In the other energy services segment, the EBITDA was negative. But I tend to think about the growth in the crude logistics business as being a pretty accretive piece of that business.

And so just wondering if you can frame for us -- you told us the truck count today, but what sort of EBITDA or EBITDA margins that business is generating today? And then, from a total segment basis, what it would take for that segment, realizing there's a lot of product or service lines in there, what it would take to get that segment back to EBITDA profitability moving forward?

To split the answer on that, first, on the crude hauling business, those margins today are in the 20% range; second part of your question, a large piece of the activity inside of the other businesses is completion-related, which faced some headwinds inside of Q3. We're seeing similar utilization today. But getting similar feedback in those business lines as we are in the pumping and sand side, that the E&P companies will pick up utilization in Q1 as their budgets are reloaded.

Your next question comes from the line of Dave Anderson from Barclays.

Guys, this is Derek on for Dave. You talked about offsetting your oil and gas cyclicality. Are you looking at this as a function of increasing your industrial footprint, or are you thinking about divesting any of your oil and gas business lines? Or a combination of both? If you can expand on that for us further, please.

We're always open to either being a buyer or a seller. But most of it is the expansion of the industrial side and moving it more and more towards being the industrial company. So we've grown to where it's about 62% of our revenues right now and we'll continue -- it'll continue to be an important part of it. Our CapEx, $98 million went to Infrastructure this year, a significant amount will go next year with -- as we see contracts and opportunities develop.

Great. And then just following up on that $17.5 million annualized EBITDA per fleet for the 3.5, if you can just expand on that further, how many of those were working for Gulfport under your contracts? And outside of that, what's driving that strong profitability that you're seeing?

We currently have 1 fleet under contract with Gulfport. The remainder is split, about half of those fleets are working under long-term relationships with existing customers and the other half is on the spot market. This team has focused heavily on efficiencies throughout the year and you can see some of that in the data, about 80% of our work inside of the pressure pumping segment was zipper fracs during Q3.

Great. And what are you focusing on, going through 2019, to continue to increase those efficiencies? Is it coming from the surface side, is it coming from scheduling with your operator? Just if you can give us some details around that?

I think the majority of the efficiencies are driven through long-term relationships with the operators. We've seen that through our long-term relationship with Gulfport as well as other customers. And we think that's really the path towards long-term efficiency, is working for dedicated operators and driving efficiencies throughout the system.

And to further expand on that, it's a utilization game, right? It's how much of your fleets that you can utilize, and we are seeing quite a bit of strength starting in the first quarter and where our utilization would go. We said we averaged 3.5 fleets active in the third quarter and we're probably looking at 3.5 to 4 as we go into the fourth quarter. But we see -- do see, and our customers are telling us that, to be prepared to start running again in early first quarter.

Okay, and then just a last follow-up, just to clarify the 3.5. Do you -- or of your 6 fleets, is that a effective 3.5? Or do you have some fleets stacked on the sidelines right now?

That's an effective 3.5. We've got a debt-free balance sheet and generating free cash flow, so all of our fleets are maintained and ready to go to work.

Your next question comes from the line from John Daniel from Simmons.

Arty, as you continue to successfully make the transition to an industrial enterprise, does it make any sense to opportunistically part ways, or at least start to consider parting ways, with some of the legacy oil service businesses?

We certainly would consider it, John. You certainly don't want to sell in a terrible market, but yes, we would consider that, divesting some of our interests. We've always -- we try to be thoughtful about both the balance sheet and about the positioning of the company, and if the right price came for some of our assets, we would do that.

Okay. I guess I'm going to try to follow up on Praveen and Taylor's questions and see if I can get you to be specific, so let's see. But as we -- the Infrastructure's just doing great, right? And I'm curious, given how strong the margins are and what you're doing there, I think a lot of us have been using the low 20%s from a margin perspective, and I guess, just in the next several quarters -- and I don't want you to give a specific number, but 30%-plus, do you have at least comfort that you're in that vicinity over the next 2 or 3 quarters?

Yes, yes.

John, it's Don. You know it's going to move around some, as per Mark's answer earlier. But 25% to 30%, 35%, somewhere in that swing and it's going to ebb and flow. And obviously, as we go through and try to pull more cost out of the system, we already have a helicopter today that is boosting a little bit of the margins there.

If we're able to add more there or any other kind of facet of the cost structure that we're currently contracting out for now, that will boost those margins. So, it's going to be a moving target, obviously. But, yes, it looks pretty sustainable for now.

Okay. And I guess a final one, big picture, Arty, take you back to your manufacturing days, but when you look at the frac market right now, what's your just big-picture take on the overall aftermarket opportunity out there and the need for it? I know you guys have a small fleet and it is well-maintained, but just, do you think the industry has to have a step change higher next year or is it stable?

I think utilization comes back fairly strong next year. And as I said, John, most of the commentary we get is budget resets, and E&Ps do not want to run outside of their budgets, they would get punished. And I think the efficiencies that you've seen over time between the drilling aspect and on the frac side led to a faster expenditure of their budgets.

We are -- we think frac is going to be fine next year, at least what we're seeing on -- we don't have a large fleet to deploy, but we see good utilization on our 6 fleets. And inevitably, the question always comes, that what would we do going into the future about -- and we still, obviously, don't see any of the pricing there to justify adding additional fleets or anything as -- much the same commentary as everybody else.

The point that we do want to make though is we are maintaining our fleets, we have them ready to go when the time does change. From a manufacturing perspective, I think there is -- there are some opportunities there to vertically integrate some of the things that we see. We see a lot of issues -- we see a lot of fluid ends, we see a lot of things that, if we were fabricating again, that we think we could take advantage of.

Okay. I guess, if I can squeeze one more in, Arty, and I apologize for being long-winded here, but if you were to hypothetically look at ordering a fleet versus rebuilding, seems like when we talk to a lot of the companies out there, both the assemblers and the providers, they frequently say, "Hey, these fleets that were built in 2011, 2012, et cetera, aren't really capable of doing the type of work that's required today, therefore, you really do need a newer fleet." Do you subscribe to that?

No, I don't. Because you usually rebuild the fleet through your -- we expense everything, we expense our fluid ends, we expense our power-ends. You keep the same trailer, but virtually you change out the engine and transmission after 10,000 hours or you rebuild them. So no, you're still capable of generating the same amount of horsepower that -- in fact, let me give you a fact that is not discussed very much.

One of the things we found, because we bought a couple of -- as a replacement, we bought a couple of Tier 4 engines, and the power that you get out of Tier 4 is considerably less than what we got out of Tier 2 and Tier 3. We were generating horsepower of about 2250 when you have a 2500 engine and transmission and it's in the 2100 on a Tier 4 engine.

So it's kind of -- obviously, we have to go to Tier 4, but it's one of those type of things that I still think the 2011, 2012 equipment, because of the way that you maintain it and rebuild it through the P&L, is still viable for long-term work in the frac industry.

Your next question comes from the line of Praveen Narra from Raymond James.

I just wanted to follow up again on the Puerto Rico margins, maybe it helps -- understand it. If we think about the costs in Puerto Rico, can you kind of break out how much of that is just head count oriented versus -- I know it's not really fixed, but I guess, more infrastructure-fixed costs in the country, or island?

Yes. The overwhelming majority of the cost in Puerto Rico is labor-related. There's some housing inside of that, but the majority of the cost in Puerto Rico is labor-related.

Praveen, this is Don. Just, if you think about the guys who were from the U.S. that are rotating down there, they're all staying in hotels, they're all getting per diem, per day. There's -- PREPA is supplying all the materials for the most part, so other than some tools, there's -- it's really labor-related.

Well -- and some of it's the subcontractors as well. Although, we've done a lot to reduce our subcontracts reliance and we're still relying on helicopters for the transmission work. We own one; we started Cobra Aviation earlier in the year and we do own 1 of the 6 that are working out there right now. So those are still high-cost basis items.

I see no further questions at the time. I will now turn the conference back over to Mr. Arty Straehla. Please go ahead.

We want to thank everyone for dialing in today during this very busy time. I want to personally thank our team. Without the hard work performed by each of you, Mammoth would not be what it is today. In particular, I want to thank our Infrastructure teams who have shown the utmost professionalism while working in a very challenging environment, have answered the call when natural disasters have occurred.

The future is bright for Mammoth and our roughly 2,200 team members, as our unlevered balance sheet will allow us to continue to grow and deliver shareholder value appreciation in the years to come.

Thank you to our shareholders for your support and interest in our company. We look forward to seeing many of you at our upcoming conference appearances and speaking with you again in February, when we release our full year earnings. This concludes our third quarter conference call. Good day.

Ladies and gentlemen, this concludes today's conference. Thank you for your participation, and have a wonderful day. You may all disconnect.