Operator: Good day, ladies and gentlemen, and welcome to the Mammoth Energy Services Incorporated earnings conference call.[Operator Instructions] As a reminder, this conference call is being recorded.

I would now like to introduce your host for today's conference, Director of Investor Relations, Don Crist. You may begin.

Donald Crist: Thank you, Luane. Good morning and welcome to Mammoth Energy Services' Fourth Quarter and Year-end 2016 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'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 differ materially 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 communications (sic) [ 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 fourth quarter and year-end press release, which can be found on our website, along with our year-end earnings presentation.

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

Arty Straehla: Thank you, Don, and good morning, everyone. If you turn to Page 2 of our earnings presentation, I'd like to walk you through some of the highlights of 2016 and give you an update as to how the industry looks today.

The first 3 quarters of 2016 were a rough period for the services industry, but we saw an inflection point in both demand and pricing during the third quarter. I'm very proud of what the Mammoth team did to not only weather the storm, but by focusing on cost controls, position us to thrive in this improving market.

We are seeing significant improvement across many of our business lines, with demand for both pressure pumping and sand. Our 2 largest segments experienced some largest growth over the past 3 months. This increase in demand should bode well for us as we progress through 2017.

The recent acquisitions made by E&P companies that totaled about $28 billion in 2016, coupled with the recovering price environment, is driving the improving rig market, which in turn is driving demand in the completion's market. We're already starting to see tightness in sand as evidenced by near doubling of FOB mine gate pricing from December with 40/70 now solidly above $30 a ton, with some selective shipments being priced above $40 on the spot market.

Pressure pumping demand is increasing as well, with our current bids approximately 20% to 25% above prices seen during the third quarter of 2016. Because of this demand, we have decided to staff our third fleet in the Appalachian Basin, which is expected to become -- begin pumping in March. The amount of pressure pumping horsepower operated -- operating today is estimated to be around 8 to 9 million, with an additional 4 to 5 million horsepower able to be reactivated for a relatively small cost per fleet, suggested by our competitors at between $2 million and $10 million per fleet, increasing the working horsepower to roughly 12 to 14 million horsepower.

Some industry analysts are projecting a rig count of between 1,000 to 1,200 rigs operating by the end of 2018. If so, we would see the need for up to 18 million horsepower by late 2018. If this comes to bear, there will be a shortage of nearly 4 million horsepower in the market. Obviously, a lot of pieces would need to fall in place for this to become a reality, but we see the start of that trajectory occurring today.

I hope that you're able to read Mammoth's recent press release outlining our expected growth in pressure pumping through the acquisition of an aggregate of 132,500 horsepower of new equipment, all of which is scheduled to be delivered by the third quarter of this year. Once delivered, we will house 6 high-pressure fleets, with an aggregate of nearly 300,000 horsepower with significant exposure to the spot market. We look forward to expanding further through 2019 as demand warrants.

This -- the successful completion of our IPO in October of 2016 and the repayment of our debt were significant accomplishments in 2016; well position us for this recovery.

As of year-end 2016, we had $28.7 million in cash, and a fully undrawn revolver with a borrowing base of $145 million, providing approximately $174 million of total liquidity.

Our Board of Directors recently approved a CapEx budget of $120 million for 2017, which includes the recent orders for 132,500 horsepower and related equipment, last-mile expansions and rig upgrades. And given our runway, we believe we would be able to fully fund these budgeted investments with internally generated cash flows and cash on hand, with minimal draws on our undrawn revolver, if at all.

On the operational front, the Mammoth team performed quite well during 2016, with full year revenues of $231 million and adjusted EBITDA coming in at $42.4 million, resulting in a margin of 18.4%. If the increase in the domestic rig count over the past 2 months is any indication of how 2017 will progress, we are in for an exciting year. We believe we are well positioned with both our pressure pumping and natural sand proppant divisions to capitalize on a tightening market.

With that, I'd like to turn the call over to Mark Layton to cover our financial performance before walking you through the performance of the individual divisions.

Mark Layton: 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 fourth quarter and full year 2016, with revenues coming in at $64.8 million and $231 million, respectively. However, lower industry-activity levels, equipment utilization and pricing for our services, prior to the recent increase in commodity prices, all contributed to the lower revenue compared to the prior year quarter and full year.

Operating loss for the quarter increased to $56.5 million when compared to the prior year loss of $20.4 million. The majority of the loss in the fourth quarter was related to a onetime noncash charge of $53.1 million, related to our corporate reorganization and costs related to our IPO. Excluding these charges, our operating loss for the fourth quarter of 2016 was $3.4 million.

On a per-share basis, the operating loss came in at $1.57 during the first -- fourth quarter of 2016, which is comparable to a loss per share of $0.68 in the prior year quarter. Excluding the onetime charges, we posted an operating loss of $0.10 per share during the fourth quarter.

Adjusted EBITDA for the fourth quarter of 2016 came in at $14.3 million compared to $7.2 million for the same period in the prior year. For the full year in 2016, adjusted EBITDA came in at $42.4 million compared to $63 million in 2015. Our adjusted EBITDA margin remained strong in the fourth quarter, coming in at 22%, up from 13% during the fourth quarter of 2015.

For the full year, our EBITDA margin was 18% for both 2015 and 2016.

As we expand into the Mid-Continent, we anticipate start-up costs to compress our margin slightly in the short term but expect our EBITDA margin to remain in the 18% to 22% range, with some upside possible depending on pricing.

Selling, general and administrative expenses decreased 12% to $5.7 million in the fourth quarter of 2016 when compared to $6.5 million in 2015. The decrease resulted primarily from lower total employment costs due to head-count reductions.

SG&A expenses, as a percentage of total revenue, decreased to 9% in the fourth quarter of 2016 compared to 12% during the fourth quarter of 2015. For the full year of 2016, our SG&A expenses were $16.7 million compared to $20.5 million in 2015.

As Arty stated earlier, we are seeing improved demand for pressure pumping across several markets. And as a result, we made the decision to staff our third fleet in the Northeast. That hiring process was started several weeks ago, and we expect to be fully staffed by early March. We get a lot of questions on the current state of the labor market and can report that we are not seeing difficulties in finding experienced people today. We fully expect this to change in the coming months as we and our competitors continue to see increasing demand for our services. As of today, Mammoth Energy's total head count is 563 as compared to 527 at December 31, 2016.

If we turn to Slide 4, we highlight CapEx for both 2016 and 2017. Mammoth Energy's full year 2016 capital expenditures came in at $11.3 million, including the initial payment for our November 2016 order of 75,000 horsepower and related equipment.

During the fourth quarter of 2016, capital expenditures were $7.6 million. Looking forward to 2017, we expect total CapEx to be $120 million. This includes $66 million for the acquisition of 132,500 horsepower and related equipment, currently on order, which will allow us to complete 3 additional high-pressure pumping spreads. Our high-pressure spreads are comprised of approximately 45,000 to 50,000 horsepower and are specifically designed for today's high-pressure work in the Utica and SCOOP/STACK.

We believe the age of our equipment, and the fact that it has been designed for this high-pressure work, will be a competitive advantage, given the current completion design and demands on the equipment. The ability to acquire these new high-pressure spreads for under $500 per horsepower, when the market is valuing spreads at more than $2,500 per horsepower in the public market, is significant.

We have allocated $29 million in CapEx for logistics, including the acquisition and/or construction of multiple fleets of pneumatic trailers and transload facilities, to enhance our last-mile solutions. $9 million is expected to be spent upgrading 2 of our horizontal rigs to make them more marketable in today's market, with the remaining $16 million allocated to well services and other energy services.

Given our balance sheet at year-end, we feel that we can fund this CapEx program through cash flows from operations and our cash on hand, with only minimal draws on our undrawn revolver, if at all.

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

With that, I'll turn it back over to Arty to provide comments on each of our operating segments.

Arty Straehla: Thank you, Mark. Moving to Slide 5, you'll see a snapshot of Stingray pressure pumping. Over the past 2 years, we've worked hard to improve our processes and efficiencies, and it's starting to show. We were able to average 6.25 stages per spread per day in 2016. This is up over 100% from 2014 when we pumped an average of 3 stages per day. While this is an impressive start on its own, we're not -- neither satisfied nor -- we are now routinely pumping 7 to 10 stages per day per fleet. This is particularly strong when considering the intense fracs getting completed.

While it would be easy to say that increases in productivity were all due to our processes, the customer we work for matters as well. Gulfport has been a great customer over the past 4 years, and the processes they have in place allow us to perform at a high level. Throughout 2016, we averaged 6.85 stages per day on Gulfport pads, with 3 recent pads pumped for Gulfport averaging more than 9 stages per day. We look forward to continuing this relationship in years to come.

Our pressure pumping fleet is expected to nearly double over the coming months through the acquisitions of an additional 132,500 horsepower to 6 high-pressure fleets, greatly expanding our exposure to the spot market.

We're pleased with our purchase price, acquiring this horsepower for under $500 per horsepower for brand new equipment. We've begun receiving the initial pumps ordered in November of '16, with those 2 fleets expected to go to work in the SCOOP/STACK during the second half of '17 based on strong customer interest. Given the job we've done for Gulfport in the Northeast, we expect that we will have the opportunity to do some work for them in the SCOOP in the future. We have not determined where our recently ordered 57,500 horsepower will be deployed as of today, instead we will wait to see which area has the strongest demand, once that equipment is ready to be deployed.

As you can see in the lower-right graph, we expect to grow our pressure pumping fleet to nearly 300,000 horsepower organically in 2017 based on outstanding equipment orders, with further expansion in 2018 and 2019 possible as long as the demand continues. We believe we have the management team and processes in place to maintain our current pace of efficiencies, even as we expand into the SCOOP/STACK, and we'll seek to continually improve as we move forward.

Moving to Slide 6. The market for sand has improved faster than we could have imagined, with strong demand starting to impact pricing. As you can see from the charts on the lower portion of the page, we delivered just over 195,000 tons of sand during the fourth quarter of 2016 through Muskie, of which 43% was sold to Gulfport. This was a company record.

The average sales price for the sand sold during the fourth quarter was $27.80 per ton, up roughly 30% quarter-over-quarter from $19.62 in the third quarter of 2016. We're able to generate adjusted EBITDA of $1.5 million during Q4 in our natural sand proppant services segment brokering sand and utilizing our logistics network. Due to increased demand for sand and rising prices, we recently restarted our Muskie processing facility, and initial deliveries were made earlier this week. We intend to ramp up the production at the Muskie facility over the coming months, with full utilization of approximately 58,300 tons per month expected in April.

The demand for 40/70 remains high, with all of our capacities currently sold out. The tightness in the 40/70 market is driving the demand for lesser grades, such as 30/50, 100 mesh and 20/40.

On the pricing side, we're seeing pricing for 40/70 in some areas in the low-30s per ton which reflects spot market trades for 40/70 over $40 per ton. When you compare this with spot market prices experienced this past December, the market has nearly doubled in approximately 2 months.

From an industry perspective, we believe the improving price for sand will lead to the restart of several current -- currently idle mines, increasing supply in the short-to-medium terms. In the longer term, we believe that the fundamental shift in E&P activity to longer laterals, shorter stage spacing and higher sand concentricity will allow the sand market to grow significantly in the coming years. IHS suggests that the industry could eclipse the 2014 highs of 121 billion pounds as early as 2019, with several other firms suggesting this may occur even sooner depending on the rig count.

Increasing sand market will drive the need for logistics. As you can see in the upper-right graph, we estimate the need for 300 to 400 sand trucks per well by 2018, assuming conservative increases in sand concentrations from 2016 levels. We currently have 22 sand hauling trucks, with an additional 40 trucks expected to be added to our fleets in the coming months to ensure we have last-mile solutions in place to support the needs of our customers in all of our operating areas.

Moving on to our contract drilling business on Slide 7. We ended 2016 with 5 rigs operating up from 4 in August, with the average day rate increasing to just under $14,000 per day. This improvement in our average day rate drove positive adjusted EBITDA of $700,000 in our contract land and directional drilling services segment in the fourth quarter of '16, which is up from an adjusted EBITDA loss of $1.1 million in Q3, and bodes well for this segment going forward.

We currently have 4 rigs operating, with another 2 rigs being upgraded to include 7,500 psi of mud systems and walking systems to make them more competitive in today's market. We expect these rigs to return to work during the second quarter to spot market rates and the current spot market rate for our rigs is approximately $15,500 per day.

We are fielding inbound calls for our 4 vertical rigs to drill saltwater disposal wells. Once demand shows several months of work and we have a clear path, we will reactivate at least one of these rigs, but we are not ready to do so at this time.

Our rig moving business continues to see strong demand from third parties, with that segment having its best month ever in December. We expect the rig moving business to remain strong as the rig count in the Permian continues to grow.

Finally, if you turn to Slide 8, let me provide a summation. 2016 was a great year for Mammoth, but we see a significant improvement in both demand for our services and pricing as we look to 2017. I'm proud of what our team has accomplished throughout the year. We now routinely pump more than 6 stages per day per fleet, with several pads averaging more than 9 stages per day.

With the recent rapid increases in sand demand and pricing, we restarted our Muskie facility, which has already begun selling sand during February, and is expected to reach full utilization of approximately 58,000 tons per month by April.

Given that the rig count continues to rise, we expect strong demand for sand throughout 2017 and beyond. Our rig business has seen increased demand from both our existing customers and others, and we are in the process of upgrading 2 of our rigs to be more competitive in today's market. We expect to deploy these rigs in the second quarter. Our coil tubing, the flowback services, while still challenged, are seeing increase in demand or providing a customer base which -- with which to cross sell our other services.

Mammoth is positioned to provide our customers with an integrated solution from mine to well hit. We remain committed to providing our customers with a quality product at fair prices, while growing our business in the areas we think will be the highest demand over the coming years. We believe that the demand for pressure pumping, sand and logistics services will continue to grow over the coming months, and we will be prepared in all 3 areas to meet our customer demand.

The stabilization of oil prices has given E&P companies the confidence to purchase more than $30 billion-worth of new acreages over the last 14 months. With the acreage now in their respective portfolios, we're seeing the effect of these purchases show up in the domestic rig count, which has been a -- which has seen a step change since the beginning of the year, up 14%. This increase in drilling is driving significant demand for pressure pumping, proppant and logistics; 3 areas where we are well positioned to capitalize on that growth. If the rig count projections come true, all 3 of our core business: pressure pumping, sand and logistics are expected to see strong demand. And we will be positioned to provide our customers an integrated approach to complete their wells.

While the energy industry will always be governed by commodity prices, which have historically been volatile, we are confident that the inflection point in the current cycle for the United States service industry occurred during the third quarter 2016.

Mammoth is well positioned in the areas we expect to see the greatest demand: pressure pumping, sand and logistics. And the delivery of our fourth, fifth and sixth pressure pumping fleets later this year should position us to meet customer demand and allow us to put them to work in an improving pricing environment at strong margins.

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

Operator: [Operator Instructions] And our first question comes from Jim Wicklund with Crédit Suisse.

James Wicklund: Talk about -- you talk about your crew you're moving into the SCOOP/STACK, and you mentioned that you might one day like to work for your partner at Gulfport, and the other capacity that you're adding, you're not sure where it's going yet. How much of this capacity addition and pressure pumping horsepower is speculative? Or are you doing this against so much demand [indiscernible] choose where you put your equipment to work? How much risk are we taking on the speculative ability to put this equipment to work?

Arty Straehla: Well, Jim, I think your points are exactly right. There is plenty of demand coming from customers. We started talking to people early on about SCOOP/STACK, and we've been very, very well received. I'll give you a couple of anecdotal-type customer requests as well. One of them came out of the Permian, I won't name the company, of course. But they asked us to be prepared when we get the STACK/SCOOP spread, to go down to the Permian, frac a series of 4 to 6 wells, and then bring the crew back because they are low on pumping services. We believe the demand is very, very high. I'll give you another anecdotal story about customer response. We had started -- on the logistic side, we had contemplated bringing things up and ordering equipment not to be delivered, and we are already getting asked for bids for the movement of sand. So we see the customer demand, we understand it, we talk about it, we think that our risks are minimized and we think that the template that we have from the Northeast and the core group of leadership that we have there, can transfer what we have. So we think the operating risk is very, very low. We think we will be able to move very good. And we think, on the customer side, we are seeing enough demand from our customers, that we believe that we will be able to put those to work. We actually like the exposure to the spot market. We -- obviously, we still have 1/3 of our fleets contracted, which gives us a clear visibility of cash flows, knowing exactly where we're at, but we think that the spot market is going to be more volatile and it's going to go up. We believe that we are timing this properly.

James Wicklund: Okay. And with Gulfport having -- I guess they'll have 2 of the spreads [ and you'll ] ultimately have 4 on the spot market or they'll have 3 and you'll have 3 on the spot market? What -- how does that work for me?

Mark Layton: Jim, what we're forecasting is to have the 2 spreads in the Northeast under contract with Gulfport, and the remaining 4 spreads working on the spot market.

Arty Straehla: But Jim, one of the logical things, obviously, Gulfport closed to [ buy ] Peruvian purchase and everything, but -- and they know we're coming to SCOOP/STACK. We've already had conversations, so I'm not going to imply there's a contractual agreement or there's any type of agreement. But let's face it, we've worked on efficiencies together, we know how to get stages pumped, we're doing -- we've done their biggest wells, and why wouldn't they want that in the SCOOP for that as well? So we think we have the potential for an anchor customer that is leading us in.

James Wicklund: Well, there's no question that having your good customer take you to a new basin is exceptionally common in the business and, especially, in the current market. So that's really no surprise. 58,300 tons in Muskie, and everybody's talking -- [indiscernible] had a call this morning talking about expanding brownfield capacity. How much expansion -- what can Muskie get up to? Or is 58 its peak?

Arty Straehla: It's about 60,000 tons per month, 720,000 tons per year capacity. And Jim, you know our story very well. We try to expand and get our -- get the best -- most efficient operations out of our existing, but we're also -- part of it's organic and part of it's acquisitions that we always have in mind. So we expect to grow in the same segment.

James Wicklund: And I would think that with what's been going on in the sand business, we're finding sand mines all over the place that we kind of didn't know existed before this boom. So...

Arty Straehla: Yes. Unfortunately, most of them are in Wisconsin, Minnesota. So yes, that's right.

Operator: And our next question comes from Jason Wangler with Wunderlich.

Jason Wangler: Maybe circling around Jim's question. Just curious about the ability to move that sand from Muskie down to the SCOOP/STACK, and maybe even the Permian as well, as you'd like to expand the reach of that asset.

Arty Straehla: Well, Jason, you know our story, we are first mile to last mile. We think that of all the -- we think 3 things get short in the upcoming upturn, and one of them is sand, one of them is frac capacity and then the other one is logistics. Here's where -- here's the way we're approaching it. We bought -- we've bought 40 trailers for different basins to make sure that we get the last-mile coverage. You saw $29 million in CapEx for our sand areas for -- this is for buildup of logistics in transload in the facilities. We're actively leasing rail cars as we speak, and we think logistics is a huge issue. We think that -- but -- and Jason, you know that I come from a manufacturing background, and we like to manage our inputs. And certainly, logistics is a big part of that, and we are trying to address every element of that as we go.

Jason Wangler: Great. And just maybe for Mark even. As we look at the CapEx budget, the $120-or-so million, how do you see that cadence as we look through it? Obviously, you have the equipment coming in here first half of the year, just kind of a run raiser, pretty spread out throughout the year or should we think about it front-end loaded? Just kind of a -- maybe a commentary on kind of the ebb and flow of that.

Mark Layton: Yes. I think, you -- at a high level, you look at it, it's fairly well spread out. Obviously, the first half of the year is front loaded with the receipt of the frac horsepower that we've announced. The remainder of that budget is heavily back loaded. So I think the short answer is, you look at the CapEx as evenly spaced out throughout the year.

Operator: And our next question comes from Praveen Narra with Raymond James.

Praveen Narra: If we kind of stick to that spot market leverage-type line of questioning, obviously, you guys still have good margins overall. And it's great to hear about the pricing increase already starting to have 20%, 25% already, so when we think about those pumping operations on the non -- on the spot market side, how far are we away from that spot market being margin-accretive to the overall business?

Mark Layton: We're not too far away, based on where we view pricing, when we'll be deploying that equipment. We're off at the bottom on pricing, as Arty mentioned in his comments. There was an inflection point in Q3. Pricing has improved. We're very near that point at which it's accretive to the business gross margin.

Praveen Narra: That's great. And then I guess when we're talking about how far out your customers are looking, in terms of scheduling activity, what are we talking about? I guess, if we just talk about the stuff that's being delivered now or even the 2 that come in kind of the next few weeks?

Arty Straehla: We are seeing a lot of activity around people wanting longer-term contracts, which is clearly indicative of the demand side of it. We are -- we certainly look and we entertain those as we go. But we believe the spot market -- and we're talking to people out in April and May for the fracs, both in the Northeast and in the SCOOP/STACK. I -- we think that customers are getting very concerned about their sand and about their capability of pumping their wells. Look, the E&Ps are on a treadmill. They've spent $28 billion in 2016, and they've got to -- they've told the markets they're going to do certain production. So they've got to complete those wells as they go. And the demand is very, very high for both contractual agreements and for the spot market.

Praveen Narra: It's certainly something I think you guys would be happy to help them with. In terms -- just kind of a last question. When we think about the potential of adding that new equipment in '18 and '19, obviously, you guys did some pretty big orders this year. I guess, what do you guys need see to go through with that? And then kind of when will you have to make a decision to make that time line happen? Are we talking, in terms of a lead time, a year, 7 months, 8 months? What are we talking about?

Arty Straehla: We were -- we thought we were very opportunistic. We picked up the first 75,000 horsepower at an average of $377 per horsepower. We got the second one at $610. The first one was readily available, and we've accepted quite a few of the units right now. The second tranche of 57,500 that we announced last Monday, cost us right at $610. So we got a blended average of about $478. And if you listen to Superior's phone call from yesterday, they talk about new builds being around $900, and the old [ extension ] that I remember is about $1,000 per horsepower. We feel very, very good about what we've gotten. Prices are going to come back to equilibrium. Guys have to order new engines, new transmissions. And that was quite honestly part of our decision-making process, where we actually were tracking the number of CAD engines and CAD transmissions throughout North America. When they got down to 30 nationwide against -- across a lot of dealers, we made the decision to pull the trigger. So my background comes from manufacturing of that type of equipment, so I know the lead times to get involved. There's another phenomenon that the market, I don't think, has really countered in, and that's the Tier 4 EPA rules that come into effect January 1 of '18. That's going to add $150,000 per engine cost. I've seen the estimates from $150,000 to $180,000. And we believe that it would -- we would probably get something on order sooner rather than later.

Operator: And our next question comes from David Anderson with Barclays. Your line is open.

John Anderson: So you talked about some of the -- kind of the supply chain things you're doing. I think you talked about the trucking. You talked about the different elements as you build out. Just curious as you bring your third fleet into the Northeast, is -- when you talk about the last-mile truck and all your supply chains, is that largely all set up already? And then as I think about you going into SCOOP/STACK, what are some of the things you need to do to build that out? I mean it seems like it's 2 very different markets altogether. Just help me understand kind of how you're thinking about all the supply chain and everything on both sides?

Arty Straehla: David, we spent a lot of time on supply chain, of course, on this. And we think that it's probably one of the most critical issues that we have that's facing us. As far as the last mile in the Northeast, we've got that handled. We've got 22 tractors. And we actually were opportunistic, we found some used equipment and took the fleet up from 17 to 22 and we've got enough of last-mile logistics to make sure. And we've got the transloads system up there with 3 transloads that we have long-term leases on, and we're in a very, very good position. As far as the lease costs...

John Anderson: I'm sorry. And along those lines, as you bring in the third one in there, there's enough excess capacity to handle that third fleet?

Arty Straehla: We do have the capacity to handle that third fleet, yes.

John Anderson: Okay, sorry for interrupting.

Arty Straehla: Yes, very clearly, we are in good shape with that and with our locations over sand mines on the CN, we've got a direct shot to it and we are in very good shape. The -- as far as the Mid-Con area, we have started gathering our transload and the land associated with where we would offload sand, and as well we would build a transload that would have a large amount of car capability. So -- and it's, you certainly -- the STACK/SCOOP in Oklahoma is a long -- about 400 or 500 miles -- 400 miles in length and pretty good in width, so we try to centrally locate those as quickly as we can. We think our competitors on the frac side, because we supply sand to them, they're going to struggle with sand. I think Halliburton's commentary was very important regarding sand and they've talked about that as well. But being vertically integrated -- and I think most of you know my history. I ran a frac company from '06 to '08, and we actually ran out of sand. And we'll never do that with our frac crews. We'll never run out of sand again with our frac crews because you actually shut everything down.

John Anderson: So along those same lines, if I look at your numbers on the frac sand deliveries you had in the quarter, 195,000 tons, how much of that was for your own operations versus others?

Mark Layton: So during Q4, about 43% of the overall tons sold was for our operations, the remainder was to third parties.

John Anderson: Okay, and how -- and does that change going forward? In other words, as you kind of move into the SCOOP/STACK do you -- how do you see that playing out? Does that number kind of stay similar? Does it change up or down?

Mark Layton: I think as you look at it and as we look at it, we supply our fleets first and everyone else secondary. That's a huge part of our vertical integration story and we believe a competitive advantage for us.

John Anderson: But your goal is to have all of your pressure pumping, so it would be sourced by your own sand, is that sort of the goal?

Mark Layton: The goal is to be opportunistic and make the most money. So when it makes more sense to supply our own sand, we'll do that, and when it makes sense to buy stand on the spot market, we'll do that. But the overarching theme is that we will not run our fleets out of sand.

John Anderson: Got it. I'm sorry, and one last question on the Muskie as you start it up. When should we start, like, which quarter, roughly, do you think we should start seeing some of those volumes start coming through on our models?

Mark Layton: We anticipate the Muskie plant running at full capacity beginning mid Q2.

Arty Straehla: Look, we'd always talked about Muskie being on a warm stack. We were bumping the conveyors, that's the way we've always talked about it, ready to go and ready to start up. We made the decision 2 weeks ago to [ do it ] and they are producing sand today. And that's -- the team has actually absolutely executed very well and we're very proud that -- and they're doing exactly what we said. That's one of the things that we think is vitally important from a credibility standpoint, you tell people what you're going to do and then you go out and do it.

John Anderson: So you said 2Q '18 or 2Q '17?

Mark Layton: 2Q '17 is when we anticipate Muskie running full capacity. We restarted that plant a couple of weeks ago. It's running now, and we've already shipped the first sand out of the plant.

Operator: And our next question comes from Daniel Burke with Johnson Rice.

Daniel Burke: Maybe to start, one for Mark. Mark, I thought I heard you allude to, as some start-up costs are incurred in the Southern U.S. on the pressure pumping side, talk about 18% to 22% EBITDA margins. I want to make sure I heard you correctly. And then I was wondering if you can elaborate on exactly when. Would that be Q2, Q3 that, that kind of range comes into the frame? Or what period specifically were you referring to?

Mark Layton: Yes, what I'm referring to specifically, is to bring on the staff takes about 30 days to onboard the staff and run them through our safety protocol. So there will be some start-up costs associated with that, and that -- we would expect that to hit Q2.

Daniel Burke: Okay and then given you'll be phasing-in the incremental fleets over the course of the second half of '17, is that 18% to 22% a good range to think about for the back half of '17 as well, given what you know now? Or do you have the potential to get up above that level?

Mark Layton: I think we've got the potential to get up above that level. Based on what we've got visibility of now, 18% to 22% is a good range. But given the overall demands on horsepower, and in Arty's comments he referenced the available horsepower and what we think can go back to work, we think there's some upside on that 18% to 22% range.

Daniel Burke: Okay that's helpful. And then just one on the logistics spend for this year. Does that budget contemplate investment in transload capacity in markets, in addition to the SCOOP/STACK?

Arty Straehla: Yes.

Daniel Burke: It does. Can you say at this point where? Or is that still...

Arty Straehla: We're still determining. It's still -- we're going to go where we see the greatest opportunity and the greatest demand. It's certainly -- it's -- we are aggressively going after the -- where [ it really will ] go. But certainly, we're still in a land grab situation with transload and all that type thing, so rather not talk about it yet.

Daniel Burke: I understand. And then maybe just one last one, since it hadn't gotten any attention. The CapEx spend then on the well and energy services side, can you talk a little about what that entails for this year?

Mark Layton: We've got some placeholders for some expansion. We've got a little bit of CapEx contemplated to support our coil tubing service line, and then we've got some organic growth baked into other energy services.

Daniel Burke: Okay. By -- okay, so other energy services is referring to the accommodations business?

Mark Layton: It's currently comprised of the accommodations business.

Daniel Burke: And you've got some growth spend associated with that contemplated for this year. Okay.

Mark Layton: For that particular segment, not necessarily for the remote accommodations service line.

Operator: [Operator Instructions] And our next question comes from John Watson with Simmons & Company.

John Watson: On Muskie, can you say what's the source of sand there and what percentage you expect to come from Taylor Frac this year?

Mark Layton: I think as you look at Muskie, we source raw sand from a third party, so none of the "Muskie sand" is sourced from Taylor. The Muskie sand is raw sand that is sourced pursuant to a contract, none of which is sourced from Taylor.

John Watson: Okay and if you all did develop your own sand mine, do you think it would be a regional mine? Or might it be in an area like Wisconsin?

Mark Layton: The short answer is yes, but we would look at both. We're very opportunistic, we're evaluating somewhere in the neighborhood of 20 to 25 different acquisitions right now. Some are regional sand mines, some are northern sand mines. We'll be selective but we're open to both.

John Watson: Okay great and then if I can switch to pressure pumping, Stages per fleet were up considerably quarter-over-quarter, what do you attribute the sequential change to? And is there a chance that, that could decline if you start working for another customer other than Gulfport?

Arty Straehla: No, even with some of the other customers that we've done in the Northeast, we have the high stage count. We -- I give credit, it's an area where we focus very much. Mark and I know every day how many stages were done in the previous day, but you got to give the credit to the operations guys. We have leadership up that has very, very experienced -- that is very experienced leadership and they know where the focus is. First and primary is on safety and then it's the quality of our services and then it's the efficiencies, with safety still being the very highest. And we talk more about safety than we do anything else with them. But I give it to the leadership -- I give the credit to the leadership and what they've been able to do in the team up there.

Operator: And our next question comes from Matthew Marietta with Stephens. Your line is open.

Brooks Braden: Hey this is actually Brooks on for Matt.

Just a couple of quick questions for me. First, as you all are ramping your sand efforts, kind of targeting that early 2Q full utilization, what sort of margin contribution can we expect? And, I guess, can you just kind of walk us through the margin progression there?

Mark Layton: The sand market has continued to run. Obviously, that impacted our decision to restart the Muskie facility, so we will be participants in the margin increases as sand prices continue to move. As we referenced earlier, 40/70 pricing has seen some spot market selective sales with the 4 in front of the price. That's up significantly from where we were at in December, and we'll participate in that spot market increase.

Brooks Braden: Okay, that's good color. And then switching to the drilling side, do you all have any plans to upgrade any additional rigs? And, I guess, how should we kind of think about the ultimate size of the rig fleet, kind of longer term I guess?

Arty Straehla: Well, as we stated many times, you look at the history of rig counts. November 1, 2014 there were 1,930 rigs running in the U.S. It got down to a low of 404 in May of last year, and then it's actually come back up to 751 with double-digit increases over the last 5 weeks. But even with that, we don't believe that it gets much higher than 1,000, 1,100, 1,200, primarily due to the efficiency of the rigs. You see a lot of commentary from the E&P operators, said, "Hey, used to take us 24 days to drill this well, now it takes 18." And so the improvement in productivity and efficiency has occurred quite a bit. Now one area that we think is open to us, we have on our rigs that we utilized in our rig segment, we have our directional drilling group. And we think that, that does have an opportunity from a technology standpoint. Wexford owns a rotary steerable system that I actually was a participating in -- a participant in acquiring a few years back and we believe that could be a difference maker. You hear a lot more about rotary steerables and the usage of those throughout, BHI is probably the best in class and -- with Schlumberger second and Sperry or Halliburton a distant third. But we believe the development of that tool, for a small cap like we are, would be a tremendous mover. So we're examining additional technology to implement.

Operator: And our next question comes from Jon Evans with SG Capital.

Jonathan Evans: Can you just maybe talk a little bit about your thoughts about kind of the pressure pumping industry and being more disciplined this cycle? There's a lot more sand going through, so equipment's going to run out or be used up quicker. And I'm just curious if you guys think that there's going to be discipline in the industry where you're going to get paid for the cost of capital because it seems like that's the concern that the market has. So I was hoping maybe you could allude to that.

Arty Straehla: Well, let me take you through a little bit of history first. First of all, when you talk about frac and fleets, it's changed considerably. 2006 through '08 we ran Diamondback Energy Services. We had 128,000 horsepower, that was 6 fleets. We had 4 in the Barnett. We had 2 in the Mid-Con area of Oklahoma. So you can see, sometimes you would take 6 trucks out there and sometimes you would take 4 trucks out there to do the fracs. All the fracs were daylights, did 12 hours a day. They weren't done at night. You look at the intensity that has grown. Right now we think of a high energy fleet, high pressure fleet being 20 units and we believe that we're going to run on 24 hours a day. I don't think there's enough horsepower out there, and I don't think there's enough horsepower in the pipeline to contemplate what's coming upon us in the area of pressure pumping.

Jonathan Evans: And then just, could I follow up with that? Is there a thought process of where you think pricing has to go for people to get a return on their -- return on capital to basically be able to fit into that because you're using the equipment so much harder today? It's going to -- the useful life's going to be lot less, right? So you got to get more on pricing up front?

Mark Layton: The intensity of fracs, to your point, is fairly intense right now. The current price is not at a point where you necessarily see a full cycle return, but the pricing environment is improving drastically. We've seen that on the sand side and in that segment. We're also seeing a fair amount of price increase on the pumping side. So to the point where you started out, the industry has shown some discipline lately and we see pricing increases. And we fully expect pricing to continue to increase, such that that's why we've opted to play the spot market, so to speak, on the 4 incremental spreads that we'll be taking delivery of.

Arty Straehla: Think about what you had in '14 before this thing started out. And you were seeing upwards of $90k -- $90,000 a stage, sand included in it, got down to where -- during the bottom, it was in the teens. It certainly is not back up to that $90,000 but we believe it will go back up and we believe it'll go -- it'll end up going higher than that.

Jonathan Evans: So it -- can I just follow up one last thing? So you said that you don't think you're at mid-cycle pricing, so you talked about that you've seen pricing move up 20% to 25%, roughly, in some areas. How much more does pricing have to get to, to get to kind of mid-cycle pricing do you think? Is it another 20% or...

Mark Layton: Yes, we would look to see a -- likely another 20% to 25% increase. 20% to 25% off the bottom is a much different calculation than 20% to 25% off the top. We still need pricing. Pricing is improving rapidly and we expect that to continue to increase. There's a lag between completion pricing and what we see in the increase in drilling rigs. We've seen the rig count increase. The completion pricing is coming. We've seen some of it, and we expect the pricing to continue to run.

Operator: And I'm showing now further questions. I would now like to turn the call back to CEO, Arty Straehla, for any further remarks.

Arty Straehla: Thank you very much and we want to thank this group for their participation in the call today. And certainly we'll look forward to seeing you in the near future as we continue to tell the Mammoth story. The stock price is up over 40% year-to-date and we're happy that it's like that. We're still not satisfied. We believe that it can go higher. We don't think we're getting the full valuation, and we look forward to adding on the additional aspects of our business that we've discussed. So thank you very much for your participation. Thanks for your support of Mammoth.

Operator: Ladies and gentlemen, thank you for participating in today's conference. This concludes the program and you may all disconnect. Everyone, have a good day.