Patterson-UTI Energy Inc (PTEN) 2017 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the second-quarter 2017 Patterson-UTI Energy earnings conference call. (Operator Instructions) As a reminder, this call is being recorded.

I would now like to introduce your host for today's conference, Mr. Mike Drickamer. Sir, you may begin.

Thank you, Skyler. Good morning, and on behalf of Patterson-UTI Energy, we'd like to welcome you to today's call to discuss the results for the three and six months ended June 30, 2017. Participating in today's call will be Mark Siegel, Chairman; Andy Hendricks, Chief Executive Officer; and John Vollmer, Chief Financial Officer.

A quick reminder that statements made in this conference call that state the Company's or management's plans, intentions, beliefs, expectations, or predictions for the future are forward-looking statements within the meaning of the US Private Securities Litigation Reform Act of 1995; the Securities Act of 1933; and the Securities Exchange Act of 1934. These forward-looking statements are subject to risks and uncertainties as disclosed in the Company's annual report on Form 10-K and other filings with the SEC.

These risks and uncertainties could cause the Company's actual results to differ materially from those suggested in such forward-looking statements or what the Company expects. The Company undertakes no obligation to publicly update or revise any forward-looking statement. The Company's SEC filings may be obtained by contacting the Company or the SEC, and are available through the Company's website and through the SEC's EDGAR systems.

Statements made in this conference call include non-GAAP financial measures. The required reconciliations to GAAP financial measures are included on our website, www.patenergy, and in the Company's press release issued prior to this conference call.

And now it's my pleasure to turn the call over to Mark Siegel for some opening remarks. Mark?

Thanks, Mike. Good morning and welcome to Patterson-UTI's conference call for second quarter of 2017. We are pleased that you are able to join us today.

As is customary, I will start by briefly reviewing the financial results for the quarter ended June 30 before turning the call over to Andy Hendricks, who will share some comments on our operational highlights as well as our outlook. After Andy's comments, I will provide some closing remarks before turning the call over to questions.

Turning now to the second quarter, as set forth in our earnings press release issued this morning, we reported a net loss of $92.2 million or $0.46 per share on revenues of $579 million. Total adjusted EBITDA during the second quarter was $79.2 million.

The financial results for the second quarter include pre-tax merger and integration expenses and impairment charges totaling $80.2 million. Excluding the expenses and charges, the net loss per diluted share would have been $0.21.

These charges include $51.2 million of merger- and integration-related expenses and $29 million of non-cash impairment charges from the write-down of drilling equipment related to the upgrade of certain rigs to super-spec capability. Andy will provide further details as to our super-spec upgrade plans.

Our balance sheet remains strong, with debt to total capital ratio of 16.5% at June 30. The second quarter was transformative -- was a transformative quarter for us. We closed the merger with Seventy Seven Energy on April 20, which strengthened our position in both contract drilling and pressure pumping, and added a new line of business for us in oilfield rentals.

Including the contribution from Seventy Seven Energy, compared to the first quarter, total revenues and adjusted EBITDA, excluding merger and integration expenses, both increased by 90%.

I am pleased that during the second quarter, Seventy Seven exceeded our expectations. As expected, the assets are of high quality and the people are hard -- are smart, hard-working, and dedicated. We spent the second quarter focused on integrating many of the back-office functions, including accounting, payroll, and the legal-entity structure in order to combine the individual businesses.

Immediately following the close of the merger, we began identifying opportunities to improve day rates and frac stage pricing for the Seventy Seven assets. I am pleased with the progress that has been made, and also excited about the further opportunities in these initiatives.

Similarly, we quickly began integrating the supply chain function. The supply chain integration is an ongoing process, and the more efficient supply chain combined with greater logistical capability has already proven its value.

Within operations, we have identified and put in place the management teams for the various segments and regions and built out the organizational structure around them. These management teams came from both Patterson-UTI and Seventy Seven Energy, and given their experience and proven track record, we are highly confident in their abilities.

We have a good start on the integration, but there is still more work to do. We continue to standardize all processes and procedures across business units. We are focused on adopting the best practices of both companies to enhance Patterson-UTI's position as an efficient contractor in drilling and pressure pumping, with a keen focus on safety, customer service, supply chain, and logistical efficiencies.

With that, I will now turn the call over to Andy.

Thanks, Mark. As Mark mentioned, the second quarter was a transformative quarter for Patterson-UTI. We closed the merger on April 20, and therefore financial results for the second quarter include 71 days of contribution from Seventy Seven Energy.

The consolidation of Seventy Seven Energy affected the financial and operational metrics that we typically discuss due to various factors, which I will describe in a moment. For purposes of comparison, we will compare reported second-quarter results with those from the first quarter, where Q1 reflected Patterson-UTI as a standalone company.

In contract drilling, demand for high-spec rigs remains strong, despite moderating oil prices during the second quarter. Our average rig count in the US was 145 rigs. On a standalone basis, Patterson-UTI averaged 100 rigs in the US during the second quarter, up 23% from 81 rigs for the first quarter. In Canada, our average rig count for the second quarter was one rig, down from two rigs in the first quarter.

During the second quarter, average rig margin per day was relatively flat at $6,710 per day compared to $6,750 per day in the first quarter. Despite the relatively flat margins, there were many moving pieces that affected average rig revenue and operating costs on a per-day basis.

First, rig pricing improved during the second quarter, but was offset by the repricing of certain rigs rolling off legacy long-term contracts and an increase in the proportion of rigs on reduced standby rates that resulted from the merger with Seventy Seven.

Accordingly, average rig revenue per day decreased $930 per day to $20,270 for the second quarter. This decrease in average rig revenue per day was largely offset by an $890 decrease in average rig operating costs per day to $13,560.

Average rig operating costs on a per-day basis benefited from a higher proportion of rigs on standby, which has minimal associated costs. Also, the larger member of operating rigs from both increased activity levels and the added rigs from the merger improved overhead absorption on a per-rig-day basis.

At June 30, we had term contracts for drilling rigs providing for approximately $535 million of future day rate drilling revenue. Based on contracts currently in place, we expect an average of 94 rigs operating under term contracts during the quarter, and an average of 60 rigs operating under term contracts during the 12-month period ending June 30, 2018.

Turning now to our outlook for the second quarter, we expect our rig count for the third quarter to average 160 rigs in the United States and 3 rigs in Canada. The rig count in the third quarter is being impacted by the expiration of contracts for three rigs that were previously on standby. Therefore, our average rig count for the US in July is expected to be 159, down 1 rig from June.

Average rig margin per day is expected to decrease approximately $400 per day in the third quarter as costs increase due to a lower proportion of rigs on standby and a slightly lower revenue per day due to the expiration of some legacy high day rate contracts.

Turning to our rig fleet, following the merger with Seventy Seven Energy, our rig fleet of 294 rigs includes 198 APEX rigs and 96 other electric rigs. We are in the process of completing the construction of our first APEX-XC, with delivery of this new rig expected in the fourth quarter.

This new design is the next step in the evolution of our original APEX 300 series walking rig and is complementary to our fast-moving APEX-XK. The APEX-XC offers a pad-optimal design with greater clearance for walking over and around wellheads on a multi-well pad, larger drill pipe racking capacity for efficiently drilling longer laterals, and it will feature a higher torque top drive from Warrior, our rig technology company.

We have rebranded the 28 PeakeRigs from Seventy Seven Energy to APEX PK. We are excited to have these rigs in our fleet. We believe these rigs are a very complementary addition to our APEX rig fleet. They have similar capabilities as our other APEX rigs and share many of the same rig components. More importantly, they share the same level of strong customer satisfaction and demand as our APEX rigs.

The rig design for which we are seeing the strongest demand is our APEX-XK, of which we have 58 in the fleet. We will believe this rig design is one of the freshest in the industry. It offers greater clearance underneath the rig floor for pad drilling, and the rig design offers quick movement between wells on a multi-well pad, typically about 45 minutes.

And it has easy mobilization between individual pads. We routinely move this rig between multi-well pads in the Permian Basin in approximately 48 hours, which has helped to make this rig design very popular with our customers.

With current drilling trends towards a greater proportion of pad drilling and longer laterals, especially in West Texas, demand for the APEX-XK has been strong, while demand for the smaller 1,000-horsepower rigs has waned. Accordingly, we plan to upgrade at least seven of our APEX 1000 rigs to APEX-XK 1500, giving them all super-spec capabilities. All seven of the APEX 1000 rigs are being relocated out of Appalachia and are planned to go to work in West Texas once the upgrades are complete.

This is an extensive upgrade that will require us to swap out the mast and substructure for the new APEX-XK mast and substructure, along with other components. We expect to spend an average of approximately $8 million per rig for these upgrades. Additionally, we took a non-cash impairment charge in the second quarter for the components that we will no longer use from rigs being upgraded.

We have contracts for 5 of these rigs with terms ranging from 18 months to 24 months, and we expect to shortly enter into contracts for the remaining two rigs. The first of these upgraded rigs was delivered earlier this month and we expect to deliver approximately one upgraded rig per month.

These upgrades will help us maintain our position as a leader super-spec rig market. We have grown the number of super-spec rigs in our fleet to 107, with all but 1 currently contracted. Across the industry, we estimate the total supply of super-spec rigs is approximately 465 in the entire US, with utilization for this class of rig exceeding 90%.

Turning now to pressure pumping, pressure pumping revenues increased to $290 million in the second quarter from $141 million in the first quarter due to the acquisition of Seventy Seven Energy, increased utilization, and better-than-expected pricing. As a result, our gross margin as a percentage of pressure pumping revenue improved to 19.4% for the second quarter from 15.7% in the first quarter.

Given current demand for pressure pumping, we expect to reactivate two frac spreads late in the third quarter and one frac spread during the fourth quarter. By the end of the year, we expect to have 23 active frac spreads, which means that over 80% of our more than 1.5 million horsepower will be active.

In addition to benefiting from more active spreads, we are also benefiting as each active spread has been able to complete an increasing number of stages due to efficiencies surrounding multi-well pad drilling and zipper fracs. On a Patterson-UTI standalone basis, the total number of stages completed in the second quarter increased 125% year over year, while the active crew count was up only 59% over the same period.

This increase in stages pumped is being impacted by an increasing proportion of multi-well pad drilling, especially in the Permian, which improves efficiencies for the operator and ourselves by reducing the amount of downtime spent mobilizing between wells. With the reduction in downtime, we require additional rotational equipment to allow pumps to cycle back to the yard for maintenance, maintenance that would have typically be done as the equipment moved between wells. Considering this rotational equipment, our average active spread size continues to grow and currently exceeds 50,000 horsepower.

As we have said before, pressure pumping is a business where scale helps to drive efficiencies. Our position allows us to work with various sand producers and has helped to improve our contract position where we have access to higher volumes of the more popular mesh size.

Additionally, we continue to roll out our centralized logistics center here in Houston that includes 24/7 dispatch personnel, central scheduling and tracking software, and smartphone apps in the field. This centralized logistics center is helping to reduce demerge costs and strengthen the advantage we have in terms of logistical efficiency.

Looking forward, pressure pumping revenues are expected to increase 25% sequentially in the third quarter. Pressure pumping gross profit as a percentage of revenue is expected to improve to more than 21%, despite the carrying costs associated with future reactivation.

Before I turn the call back to Mark for his concluding remarks, let me provide an update on several other financial matters. Our other operations include Great Plains oilfield rental, our E&P business, and Warrior rig technology.

For the third quarter, we expect other operations to generate revenues of approximately $23 million, with a gross margin as a percentage of revenues in the high 20%s. Depreciation expense for the third quarter is expected to be approximately $205 million. SG&A for the third quarter is expected to be $26 million.

We are currently projecting our effective tax rate to be approximately 36% for the second quarter. CapEx for full year 2017 is now expected to be $580 million, an increase of $130 million from our last earnings call. The increase consisted of an additional $70 million for rig upgrades, $50 million for pressure pumping, and $10 million for E&P, Warrior, Great Plains, and general corporate CapEx.

With that, I will now turn the call back to Mark for his concluding remarks.

Thanks, Andy. To risk stating the obvious, there is considerable pessimism concerning oil prices and the state of the oil markets. Optimism in late 2016 and early 2017, arising from oil prices above $50 per barrel, has turned to pessimism, as oil briefly touched below $43 per barrel in June.

Our consensus appears to have arisen among analysts and investors that oil and natural gas prices will be lower for longer. In other words, the consensus is that commodity prices will not be meaningfully higher in the second half of 2017 and maybe not even in 2018.

Against this backdrop, what's happening for Patterson-UTI? First, by and large, we have not seen our customers decide to drop rigs. And in fact, based on contracts we have already signed, we expect to see our rig count increase slightly over the next few months.

Although the rate of increase in the second half is not likely to approach the rate of increase in the first half of 2017, we don't see an impending decline in drilling activity by our customers. Put simply: the technology advances in drilling have made it economical for E&Ps to continue to be active, even in a $45 to $50 oil market.

The staggering development of advanced rig technology is now often taken for granted. For that reason, I think a few words about those developments are warranted.

Some of the technology advances, such as walking systems, no longer seem cutting-edge, but continue to have a profound impact on efficiency. The continuing adoption of multi-well pad drilling is reducing non-productive time by allowing a rig to move from well to well in 45 minutes as compared to multiple days when moving between single-well pads.

Additionally, as walking systems offer greater flexibility in the way wells can be laid out on a multi-well pad, advances are leading to a larger number of wells per pad.

Other advances, such as high-pressure circulating systems on drilling rigs, are not only helping to drill faster, but are aiding in being able to do to drill longer horizontal lateralies (sic). Additionally, efficient contractors are offering great value and helping to improve well economics by quickly drilling these complex wells.

More efficient drilling is, of course, just one part of the story. Greater productivity through longer laterals, greater number of stages, and other technology improvements in pressure pumping are also key elements of making it economical for E&Ps to sustain their activity levels at these commodity prices. In pressure pumping, there are other factors that bode well for continued high levels of activity during the balance of the year.

We believe that many E&Ps were delayed in getting their wells fracked in the first half of the year for a variety of reasons. First and foremost, in order to deploy a frac crew properly, more than 100 people need to be hired and trained. In a world of low unemployment, this takes time, and the time it takes meant that even when E&Ps were ready to pay a reasonable price for pressure pumping services, crews were not immediately available.

In addition, we believe that faced with unsustainably low pressure pumping prices during 2015 and 2016, a large amount of the frac capacity in the US industry was cannibalized. As a result, the supply of ready-to-activate equipment is lower than what was commonly believed.

Another factor is that the longer horizontal laterals, combined with advancements in completion designs, are leading to more stages per well. When combined with the greater sand loadings called for with these new completion designs, the resulting well has greater reservoir contract, leading to higher well productivity. The impact of the pressure pumping industry has been an increase in the amount of time it takes to complete a well positively, if affecting pressure pumping demand.

Finally, the pace of pressure pumping reactivations has not kept up with rig reactivations, leading to an increasing number of drilled-but-uncompleted wells, so-called DUCs. With the current level of DUCs, we see demand for pressure pumping services staying strong in the second half of 2017.

As we see it, our US land customers have demonstrated that they can stay active in the current commodity price environment. For that reason, I've said that $50 is the new $80 for US land. Perhaps in retrospect, I should have said that $45 is the new $80 for US land.

The current oil market offers Patterson-UTI, with its US land focus, additional benefits. Current oil prices and market outlook do not encourage offshore drilling and production. Moreover, as everyone is well aware, even in some of the countries that have drilling and completion breakevens lower than or on a par with the US are finding themselves challenged due to the impact that social costs have on their economics.

With a lower marginal cost of production combined with no political or currency risks and very little geological risk, economics favor North America onshore -- again, favor North American onshore -- over many of the international and offshore markets. Thus we think Patterson is uniquely positioned to prosper in this type of commodity market environment. Patterson-UTI is the only company that is a market leader in the US in super-spec drilling and pressure pumping.

Thurs, for many reasons, we are upbeat about Patterson-UTI's prospects, even in the lower-for-longer consensus about oil prices. While we do not have a crystal ball about oil prices, we think that if oil stays in the $45 to $55 area, we will be very active in both drilling and pressure pumping. In this commodity price range, efficiency is critical for the E&Ps to make money, and this plays to our strength.

While we acknowledge the general pessimism respecting oil prices, we also want to equally acknowledge that there are some who think that inventories are indeed decreasing and we may indeed see higher oil prices in the second half of 2017 or in 2018. While we cannot add anything meaningful to the discussion of world oil prices, we can say that our recent experience is that if oil is above $50, rig activations will accelerate.

With that, I would like to both commend and thank the hard-working men and women who make up this Company. We appreciate your continuing efforts. Also, I am pleased to announce today the Company declared a quarterly cash dividend on its common stock of $0.02 per share to be paid on September 21, 2017 to holders of record as of September 7, 2017.

Operator, we would now like to open the call to questions.

(Operator Instructions) Marshall Adkins, Raymond James.

Mark, thank you for recognizing that there are at least one of us still out there thinking oil moves higher. And in that vein, I'd like to get a little more insight into the remaining frac fleet that has not been upgraded and reactivated.

Best I can tell, you maybe have another 300,000 that you could upgrade, Andy, next year. If oil does participate and move higher, what are your plans for that and how much will it cost per fleet? I'm assuming the cost as you get further into the inventory keeps going higher per fleet, but give us some sense of your thoughts there as well as the cost to do that.

So let me back up a little bit in the story. You know, right now, we see the rig count essentially flat to slightly up in the US market. But pressure pumping activity has been lagging rig count all year long. And so we still have the opportunity to continue to activate more spreads this year.

By the end of this year, we will have activated 23 spreads total, active, and that's going to be over 80% utilization for us. So just given the math, we still have a number of spreads that we can activate in 2018. And so if rig count continues on track the way we see it at today's commodity price, we think we are going to be very busy in pressure pumping.

I think the key is, whether or not we activate any more spreads in 2018, we're over 80% now. And I think the industry is going to be in that same range. And when the industry is at 80%, it really starts to tighten things up in terms of availability for crews at certain times. It tightens the schedule for everybody. And that's when it really starts to drive the pricing as well. And we saw that back in 2014.

Right. So how much is it going to cost for the additional capacity to bring it back out?

So when we were originally reactivating spreads last year, our earlier spreads were in the $2 million range. As we work through the fleet, we get into $3 million. I think the additional spreads of the three that we'll activate this year and anything into 2018 would cost us in the $4 million to $5 million range per spread.

Perfect, makes sense. All right. You guys seem to have done meaningfully better than most of your peers, both in terms of revenue improvement, but also margin improvement, on both sides of your business.

How much of that was due to the Seventy Seven Energy integration, and can you give us some thoughts on how that integration is coming? Have there been any surprises? It seems like from looking at the outside, it's gone extremely well and that helped to contribute to your outperformance. But just give us some color on that, if you would.

Sure. You know, we closed that merger back in April. And we really had less than a month towards the end of the quarter to do a lot of reconciliation and take a deep dive into operations, financial numbers, and things like that.

At the same time, there was a lot of work being done to start to prepare for the transition, to really fully integrate such things as back-office. So on July 1, for instance, we went live with all systems on the same ERP. We transitioned from the previous SAP system that they had; we got everybody on Oracle.

In July, we were able to migrate all the employees over to the same payroll system. All the legal entities were moved for the July 1 when the ERPs were put in place. So there's been a lot of work and a lot of heavy lifting by a lot of people across the Company.

And so I want to commend everybody for all the efforts and all the time that everybody put in. So there's been a lot of work on the back-office.

At the same time, we've announced the leadership positions for the different businesses, leadership teams. So a lot of work that's been going on. There's supply chain has been working to integrate things. So we believe that we are on track for what we previously discussed, at the $50 million in synergies on an annualized basis. And we have visibility on the majority of those synergies today.

Thank you, all.

Chase Mulvehill, Wolfe Research.

Good morning. I guess the first question -- I just kind of wanted to come back to the centralized logistics center. And then maybe just kind of help us understand how accretive and how helpful that was to the pressure pumping business in Q2. And then as we go forward, how much you think that this can continue to add to margins as we go forward.

Well, without getting into the details of some of the numbers behind the benefits, I'll give you some general qualitative analysis of what's happening. So as we work through the process to centralize logistics, and on our previous call, we said that we were already running all of Texas from the centralized logistics center.

And today we are working to move the Mid-Continent operations into that. And before the end of the year, we will be getting the Northeast into the same center.

So the real efficiency there is the ability to move trucks to locations and just maximize the amount of time that the trucks are spending moving the sand, and just managing the overall efficiency. Some of these are our own trucks; some of these are third-party trucks.

We are also paying attention to where railcars are. And so there's just a lot of work there to make sure that we are very efficient on how sand moves to the well site. And that we are minimizing any of the demerge costs.

And so when we were managing in the regions, it was manageable up until about last year, when sand volumes per well just started to move to the levels that they are today. And then once you're pumping full unit trains, if you're not careful and you're not watching what's going on on a 24/7 basis, you can have trucks that aren't rolling. And you could incur demerge costs in various places without even knowing it.

So this gives us that level of efficiency to get the costs down. It also makes us relatively popular with the trucking companies because they can be efficient. Trucking companies want to move trucks, and we can help them do that. And so in some basins, we've become a preferred partner for some of these trucking companies to work with. So very pleased with the results we are getting in general.

Okay, all right. Thanks for that. And I guess one last one. On the SCR rigs that you have, are you planning to upgrade any of the [APEX SCR] rigs to AC rigs? Or is it just the 1,000-horsepower rigs that you are upgrading?

So the rigs that we are upgrading are APEX 1000s, and we are taking these up to APEX-XK 1500s, as we talked about today, and that's what we have planned right now. And we will fill you in at the next earnings call on any future changes to that.

But suffice it to say, the demand for super-spec rigs in the market is still strong. We have all of them working except for one, which is in a basin is a little bit off the beaten path away from the Permian.

But right now, we really need to get some more super-spec rigs in our fleet just to meet the requests from our own customers today. And so that's what we're doing and that's why we are working through the upgrade process.

Okay, I will turn it back over. Thanks, Andy.

Scott Gruber, Citigroup.

Good morning. Great quarter, especially given all the moving pieces.

Thank you.

Andy, you mentioned the improvement in stages per day that the legacy Patterson frac fleet is achieving. Is there a gap in stages per day that the legacy Patterson fleet and the legacy Seventy Seven fleet are achieving? Is this an area that you can exploit for improvement down the road?

No. The only reason that we called that out in terms of legacy Patterson-UTI is we have the data. We have the historicals. So that was the only way we could make a reference.

What we were really trying to show you -- and I'm sure that other pressure pumping companies are seeing the same thing. But as the industry shifts more towards multi-well pads, especially in the Permian, the operators are becoming more efficient and that makes us more efficient. And so we are getting better returns on our assets to be able to work in that manner, and so that's helping overall margins in general.

But no, there's certainly no difference between how legacy Seventy Seven is working in the Patterson. It was just because we had the historical data.

Got it. And I'm trying to think about where you can take your pressure pumping margins here in the absence of any spot price improvement. After you get through your deployment plans, where can you take your gross margin?

And I'm thinking about after the reactivation cost with any improvement in asset during the year you're able to achieve down the Permian and elsewhere -- cost-structure improvements. You know, you are heading towards 21% in 3Q. Where could you take that number after these factors are in the past, but without any other -- any further price improvement?

So, yes, as you mentioned, we're projecting to get to at least 21% in the third quarter on a gross margin level. That does include the cost of reactivation on the other spreads that we've discussed as well.

And that cost is mostly labor, so it's a big cost at the expense lines to start to bring people in. You got over 100 people on a frac crew, and we're going to have them on for a month or more per crew before the crew generates any -- before the spread generates any revenue.

You know as well, it's hard to say what will happen as we get into 2018. But as I mentioned earlier, our utilization is going to be over 80% and I suspect other pressure pumping companies are going to be over 80% as well. And when we are at that level in the industry, it's tight. I mean, it feels tight.

When operators are calling, trying to book dates on the calendar, it becomes harder to get -- you know, there are uncertain days. And it does create this tightness in the market that I think there's potential to move pricing past that point as well.

We mentioned a number on the last call, and it's really about the same on this call. About two-thirds of our equipment in pressure pumping is not tied to contracts right now or not tied to pricing agreements. So from that respect, I think we do have the ability that if we get some more pricing traction in the market towards the end of this year and into next year that we still have the ability to move that as well.

And can you remind us when the contracted frac fleets reprice?

You know, there's no waterfall coming. There's just -- there's various contracts at various times going out into the future.

Okay. Appreciate the color.

Jim Wicklund, Credit Suisse.

Good morning, guys. Your pressure pumping increase was nothing short of exceptional, so congratulations on that.

I'm curious. How much of your pressure pumping revenues were sand revenues? I ask that because we've heard companies report as much as 60% or so of their pressure pumping revenues are for sand sells. And on the sand that you do buy and mark up and pass along, are your margins better on sand than sheer pumping, or is it the other way around?

So we still provide for the majority of our customers the sand. And there are of course customers that provide their own, but the majority of our customers, we provide the sand. And I wouldn't say there's been any real shift on a quarter-to-quarter percentage basis in that percentage.

In terms of margin on sand, we've seen some cost increases in sand on our side from Q1 to Q2. It's not been as high as what I've heard reported. For us, from Q1 to Q2, we've seen sand costs increase at little bit less than 10%, and especially in the Permian, it's only been less than 10%.

But we still get a margin on that sand, but we still get a higher margin on the service aspect than we do on the sand. And the sand volumes are big, the cash is nice, but the actual margin on the sand is not as high as what we charge on the service itself.

And Andy, what percent of your pressure pumping revenues do you think are the sand sells?

I don't have that number in front of me right now. But it hasn't changed quarter to quarter in general.

Can you -- well, we didn't know what it was last quarter. Can you ballpark me? Is it 20%? 50%? 70%? I won't hold you to it.

It's in the range of about 35% to 40%.

35% to 40%, okay. Thank you. And my follow-up, if I could. You say there are 465 super-spec rigs out there in the market; you're upgrading 7 of your APEX 1000s -- upgrading. There are 700-plus horizontal rigs running.

Even at a flat rig count, which you clearly don't expect -- which is great -- the market will continue to replace these non-super-spec rigs over the next couple of years. Where do you get the rigs to do that? Do you have to start getting newbuilds if you run out of upgrade potential, if we are just -- like I say, even if we are churning at a current rig count, just swapping out, to your point, the rigs that are out there with super-spec rigs, where do those rigs come from for Patterson?

You know, right now, we have the upgrade plan that we're working on, as we discussed today. There could be some upgrades in the future. I think it's important to note that we don't believe that the market is there for the economics on newbuilds. And it's just not there today.

So we don't see this wave of newbuilds coming into the market yet, but we still see the potential to upgrade the rigs. We've chosen to discuss what we're doing now because it's important for the business, important for you to know we are increasing CapEx to do it. But we're getting contracts to do this as well, and so the economics on these upgrades make sense.

Now, further, more intensive upgrades that may take more than $8 million, that may materialize before newbuilds. So I don't see newbuilds in the near future.

Okay. Thanks, guys.

Byron Pope, Tudor, Pickering, Holt.

A question related to the one that Jim just posed. And just wanted to get specific, if we could, with regard to the incremental APEX 1000 rigs in your fleet that might be candidates for upgrades to APEX-XKs over time, if the economics warrant.

So yes, we have other 1,000-horsepower rigs in the fleet that could be potential candidates for an upgrade at some point. Of course, we've chosen to take the ones that make the most economic sense right now. And the economics on the contracts we are getting good and certainly give us a good payback on the $8 million investment.

I think we'll have to wait and see what kind of improvement we see in the market going forward as to whether or not some of the other rigs in the fleet could be candidates.

And is it reasonable to think that you would need the same type of term contract coverage that you've got on the five that you are currently upgrading to make the numbers make sense in an uncertain environment?

We certainly would like to see some kind of commitment from the customer. The rates on these rigs are in the low 20s, so from an economic standpoint, it does make good sense. So we want to see similar type economics in order to proceed with further upgrades.

Okay. And one last question for me on the pressure pumping side. It seems as though you guys have historically done a great job of putting incremental spreads to work for existing customers in your core basins. Is it fair to think that that's the case for the spreads that you are adding in the back half of the year?

Yes. Yes, we expect them to be similar. With some potential new customers in the mix as well.

Appreciate it.

Sean Meakim, JPMorgan.

Maybe just to follow on a couple things you've already discussed, a couple finer points. I think on the 1,000-horsepower rigs that you are upgrading, can you maybe just walk us through how you think about calculating that payback?

So I guess I'm thinking about if you're laying out $8 million of capital, you've done a contract of maybe 18 to 24 months, is it looking at just the incremental rate versus the other rig? Or do you take into account, as you talked about, the demand for the 1,000-horsepower rigs are waning, such that perhaps there's a utilization adjustment and so we'll be able to work this asset much better?

And kind of how we think about that. And what you think the payback would be on these types of rigs. Is it -- or on these capital commitments, is it 3 to 4 years? Is it within that 18 to 24 months?

So as we mentioned, the cost to do the upgrades is around $8 million per rig on average. The rates we're getting on these is in the low 20s, so there's good economics there to get us a payback in about a three- or four-year period looking at margins and the rig itself. But we also have to recognize that there's just not a strong market for 1,000-horsepower rigs. The market has evolved.

You know, there was a time when an operator might pick 1,000-horsepower rigs because it was a lighter rig, easier to move, quicker to get from pad to pad. But now look what we're doing with XK 1500s. We are moving these rigs in two days or less between pads in West Texas and South Texas.

So operators look at the efficiencies that they can get out of a rig like a 1500 XK, and the 1000 has just become less interesting. So this is a very worthwhile investment for us; it extends the life of the rig by another 10 years or so. So it's certainly a good investment for the long term for the Company.

Sean, I would just add one additional thought, which goes as follows. These rigs were originally built looking at the market in the Northeast when there were enormous trucking and load restrictions. They were specifically designed for that kind of problem and that kind of need.

Those laws were changed. The market in the Northeast changed. And for any number of reasons, these rigs, which is basically 10 years old or longer, are no longer the most fit-for-purpose rigs. And we see an opportunity, as Andy said, for approximately $8 million to take a rig that is no longer in high demand and turn it into a rig that is in extremely high demand. Those economics are incredibly worthwhile from our perspective.

So these rigs will come out of Appalachia. They'll go onto the Houston yard for upgrades and they will find their way over to West Texas.

Got it. No, it makes sense to me; I just think it's helpful to walk through some of the math. So I appreciate you guys doing that for me.

I guess just one more on the Seventy Seven Energy integration. You touched on it, but maybe I was hoping you could go a little bit deeper. Just as you're going through this point, you said good line of sight in terms of hitting the synergy targets.

But I guess as you look at the supply chain portion of that, any issues that have arisen and/or opportunities that maybe you didn't know before you got the chance to look under the hood? Just thinking about what that opportunity set could look like within supply chain for Seventy Seven.

There's certainly a lot of cost-saving potential. We had a larger company with a larger footprint and a very good supply chain operation and logistics; they did as well. We had stronger negotiating power on a lot of the contracts that we had in place.

So we are able to roll legacy Seventy Seven purchasing into Patterson-UTI supply chain. And there's going to be significant annualized savings from that.

All right, fair enough. Thank you, guys.

Marc Bianchi, Cowen.

Thank you. Very nice performance, and nice guidance as well. I guess where I wanted to go was on pressure pumping. If I look at the guidance that you've provided for the margin improvement in pressure pumping -- appreciate that there's some reactivation costs there in the third quarter, but there was also some in the second quarter.

If I try to normalize for that, I still get an incremental that's maybe in the low 30%s in terms of percentage. I would have thought that could be better, with the tightness in the market and the pricing improvement that we're hearing. Is there anything on the cost side that might be offsetting that? Is it just conservatism? Curious to hear your thoughts around that.

I think it really gets back to the pricing and the market challenges. I mean, you have to think back to where we were on pricing at the bottom in 2016. You know, pricing in pressure pumping across the industry had been pushed down 70%, which means to get it back to where it was in 2014, we have to more than double pricing from where we were.

So when you hear about 30% increases and 50% increases in pricing, we have to get it more than double to get back to where we were in 2014 from an actual price-per-stage standpoint.

So where we are in the market today, you know, the industry is probably still a bit short of 80% utilization. There is some tightness in the market, but you're not going to get the wholesale pricing power until we push past that 80% utilization.

As I mentioned, once we have 23 spreads deployed, we will be over 80%. I think the industry will be in that 80% level as well. And I think that is why there is future opportunity for pricing improvements.

Okay. Maybe on the cost side, you mentioned the sand costs and not being such a hurdle there. Is there anything else on the cost side that might be changing? You know, we've heard about trucking and talked about that before. Labor sounds like it's tight; it's taking you guys longer to source the labor that you need versus what it was at the end of last year. Can you talk to some of those factors as well?

Well, I'm never going to say that there's no improvements available on the cost side and we'll continue to work to be as efficient as we can. But nothing changes the fact that this business had a pricing problem, and that was driven by the downturn that we've been in for two years previous. And we just have to work the pricing back up to better levels.

And I think you're seeing that in the results going from Q1 to Q2 and then going from Q2 to Q3. We are always a bit cautious as to how much our teams will be able to get in terms of pricing push.

Two-thirds of our equipment is still working on the market where it's not tied to contracts or pricing agreements, so we have the availability to push. We just have to wait and see how much traction we get as we work through the year.

Okay, thanks, Andy. I'll turn it back.

Ken Sill, SunTrust Robinson.

You know, the integration seems to be going well. You're adding capacity. I am curious, though. You're at 80% by the end of the year, above 80% in terms of marketing capacity.

But if you look at the fleets that are actually working, what percentage of the available days in a quarter can they actually be online pumping? You know, if they were at maximum utilization? And where are you today? Do you have that information?

Well, the majority of our spreads work 24 hours a day, and I'll tell you that the calendar has been essentially filled out since the first quarter. There just aren't a lot of open days in the calendar, and that's why you see us continue to activate spreads. It's just really difficult to get more days into the existing calendars with the existing spreads.

I mean, you know, my experience is you generally need about three or four days a month for maintenance, and you lose some time for moving. So I guess what I'm getting at is the pad drilling will allow you to get (inaudible) utilization out of your units. But I mean, is there a limit to how many days a month you can actually have a pressure pumping trailer working?

Essentially, if you are managing the rotational equipment correctly, it can work 31 days a month. And so that's what we're moving to. As we do more and more pad drilling, we certainly have the downtime for moving between multi-well pads. But we also have places in West Texas where we set up and we can actually frac more than one multi-well pad from the same location without moving into our frac spread.

But that's why we wanted to discuss the rotational equipment. It's part of the horsepower that we have to account for. And so the frac spread is going to be on rotation for long periods of times, and we're going to rotate pumps in cycle and we're going to rotate blenders in cycle. So we have to take all that horsepower into account in order to run the business these days because we just don't have a lot of empty days in the calendar.

I mean, so you essentially have to have some capacity that's rotating back and forth for maintenance.

Exactly.

I was trying to get the feel for how much of that would be of your quote-unquote working horsepower.

Yes, we just -- we haven't called that out, but we are over 50,000 horsepower per spread taking that into account.

Oh, okay; that explains that number, because that seemed high. Okay. And then some of your peers have been talking about sand volumes per well. Did you guys see any shift in the sand volumes per stage or per well, Q1 to Q2?

We saw it move slightly up with our customers. And we just haven't -- we don't see anything on the horizon that shows it going down for us.

Okay, that's good. And then obviously this move to pad drilling would imply that you're going to have more DUCs, just because you got to complete all the wells -- I mean, drill wells before you start completing. Is there a trend in pad sizes in the Permian right now? Are they getting bigger, or is it kind of five wells? Is that -- or settling on kind of an optimal size yet?

It's been a multiyear shift in the Permian, which is why we called out the year-over-year staged increase. And it's been a multiyear shift from single-well pads to multi-well pads. You're seeing a high percentage of multi-well pads in the Permian, which makes us more efficient, makes the operators more efficient.

And then there are cases where you do have operators that are putting on a larger number of wells per multi-well pad as well. So that's just an evolution in the Permian. Other basins like the Marcellus, Bakken, DJ, even to some extent South Texas have started that earlier and it just took longer to get all that going in the Permian.

Yes, and then one last question. You know, I know that pad sizes and pad design were a big deal up in the Northeast because you're basically having to carve a pad out of the side of a hill.

Are there any constraints on how big pads can really be in West Texas? You know, in terms of do you have to keep the wells tightly spaced or not? I guess the impression in general is that it's pretty empty out there and there's lots of room.

Yes, certainly for everybody who's been to West Texas, you know there's not really a constraint at the surface. It's really more about the subsurface and how the operator wants to lay out their horizontal wells.

What kind of spacing do they want? Or intend to have? Do they intend to do horizontals in STACK plays where you have horizontals in multiple layers, and so that could increase the number of wellheads. So it's really more about the subsurface in West Texas and the strategy of the individual operator as to how many wellheads you end up with on the pad.

Okay, thank you very much.

Judd Bailey, Wells Fargo.

Thank you, good morning. Wanted to follow-up on one of the comments earlier, Andy. You mentioned that you had -- I think you said two-thirds of your fleet is not tied to pricing agreements.

And I just want to make sure I understood. Is that suggesting that two-thirds of your fleet, are you kind of at leading-edge pricing? I'm trying to get a sense of for the second and third quarter how much of your pressure pumping equipment is at what is kind of leading-edge. And how much would be left to perhaps reprice in the next couple of quarters.

So I guess that's one way to look at it. You know, with two-thirds not tied to contract or pricing agreement, our teams are continuing to push the pricing on those particular frac spreads with those customers.

And your ability to do that varies between customers, varies between basins, so not everything moves at once. But we do have the ability to keep pushing, and we'll just have to see how those negotiations go as we work through the year.

Okay. And I guess just to follow up on that, then. For, say, the second quarter, is there an estimate on how much of your equipment would have been at kind of the leading-edge? It sounds like it would have been far less than that two-thirds, if I understand you correctly.

You know, it's close. Close enough [for] --.

All right. And then just kind of a broad question. You guys are a bit unique with the rig business and the pressure pumping business. As you talk to customers for both sides, I'm just curious.

Are you observing any differences as you're talking to customers on contracting rigs for the next few months versus pressure pumping? Is one a lot more active than the other? I would imagine pressure pumping is, but I would just be curious to get your thoughts on any observations in terms of conversations with customers between the two businesses.

You know, first, there's no question, and I think we're not the only ones that are seeing this. The pressure pumping activity has just lagged the increase in the rig count, and that's why you're still hearing us talk about activating spreads in pressure pumping. And we still expect to be very busy in pressure pumping.

At the same time, on drilling, I think there's been more concern in the market with the changes in the commodity prices that somehow rig count may drop. We just don't have that view.

As an industry, I think at today's commodity price, we are flat to slightly up as an industry. For Patterson-UTI, we expect it to be slightly up toward the end of the year, and that's how we see it. I think there's also a continuing high-grading in drilling to super-spec rigs, which produce things for contract (inaudible) like ourselves.

And if I could follow up on that last point. There's a lot of different opinions on how much the rig count may or may not drop next year, but if it's down, I don't know, 100 or 150 rigs, but you also are in the middle of this kind of industrywide high-grading process, how would you -- if the rig count is down, say, 100, how would we think about Patterson's rig count as you upgrade rigs?

Do you think -- is it inconceivable you could keep your rig count flat. Or do you think you would still soften, but maybe less than the market, as you upgrade more rigs to super-spec?

You know, it depends on the timing of when we're putting out rigs that are upgraded and creating more super-spec rigs in our fleet. But it is conceivable that total industry could drop the 100 rigs and we could still have a flat rig count, depending on the timing of when those upgrades come out.

Okay, great. I'll turn it back. Thank you.

Kurt Hallead, RBC.

So I had a just follow-up question on the land rig front. You guys talk about the prospects for upgrades. You talk about the dynamics in the market where pricing is not supportive of newbuilds.

So if you're looking at upgrades, do you already have contractual commitments in hand from customers to justify those upgrades? And then what day rate or what cash margin is required in your mind to move forward with an upgrade? And what's the cash margin required for a newbuild?

So, you know, for the seven rigs that we've talked about that we are upgrading, which are APEX 1000s that we're moving to APEX-XK 1500s, of those seven, five are currently contracted. We expect to sign the other two in the very near term.

And we're going to get day rates in the low 20s for these rigs. And so we think for the $8 million cost of these upgrades that the payback is good and it's the right thing to do for these rigs for the market.

And then what's the cash margin needed for a newbuild, in your mind?

It's got to be a bigger revenue than low 20s. You know, newbuild rigs -- and we completed one new XK and we're building an XC and they are under term contracts. We need to see rates that are higher.

We said on a previous call that the new XC that we're building, we've got a contract with rates in the mid-20s. That's closer to what we need for newbuilds, and the market's just not there yet. But the market is good for progressing the upgrades right now.

Okay. And I know you mentioned earlier in the call in response to a question about the repricing of frac, but you also have the prospect of repricing some of the Seventy Seven Energy rigs as well. So on the land rig front, how much -- how far along are you in that repricing process? One-third, one-half? You know, any general gauge of where you stand on the repricing on the land rig front?

Yes, and just to kind of explain where Seventy Seven was again. You know, Seventy Seven had a single customer at one time. They had to branch out and get customers in other basins during the middle of a downturn, which is a very challenging prospect. And so some of their pricing might have been lower than others in order to do that, but that's what they had to do in order to get the work.

You know, there has been some opportunities to do some repricing. We've done a little bit already and we'll continue to work through the year and do more. It's hard to say the timing of some of these, but we'll continue to be working on that.

Okay. And then maybe to wrap up on this one. With the incremental frac capacity that you've added here, a question for either you or Mark or both of you. What do you envision Patterson being? A service company or a land driller five years from now?

Well, if you look at the projected revenues, we're looking more like a pressure pumping company than a contract driller. But we are very pleased to be in both businesses.

Great answer. All right, thanks, gentlemen.

John Daniel, Simmons and Company.

First one, Andy, would be have you guys contracted any sand yet from any of the emerging West Texas sand mines? And if so and doing that, would you expect this to have any impact on the margins?

You know, I would say that the West Texas sand mines are as you put it: still emerging. And so we do intend to take some sand at some point, but we haven't got sand from them yet. But we also haven't seen a huge push on our sand costs. From Q1 to Q2 in the Permian, it's still under 10%, so that's kind of where we are on sand.

Okay. Does it ever make sense -- just given how big you are out there, does it take makes sense to potentially buy your own West Texas sand mine?

Well, I think we prefer to stay in the businesses that we are very familiar with as opposed to the mining business. But we have made investments in the mines in past and we've done other types of deals with mines to ensure sand supply. And I think we'll continue to look at those types of prospects.

Fair enough. And you addressed this early on -- I apologize. But have you placed any orders for new frac equipment yet? And if not, do you expect to place orders for equipment before year end?

We have not placed any orders for new frac equipment and we do not have plans to place orders for new frac equipment.

Okay, thank you, guys.

At this time, I'm showing no further questions. I would like to turn the call back over to Mr. Mark Siegel for closing remarks.

I would like to thank everyone for their participation in our call today. We look forward to speaking with you after our third quarter. Thanks, everybody.

Ladies and gentlemen, thank you for your participation in today's conference. This does conclude the program; you may now disconnect. Everyone have a great day.