Patterson-UTI Energy Inc (PTEN) 2014 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the quarter-one 2014 Patterson-UTI Energy Incorporated earnings conference call. My name is Darren, and I will be your operator for today.

(Operator Instructions)

As a reminder, this call is being recorded for replay purposes. Now I would like to turn the call over to Mike Drickamer, Director of Investor Relations. Please proceed, sir.

Thank you, Darren. Good morning, and on behalf of Patterson-UTI Energy, I would like to welcome you to today's conference call to discuss the results for the three months ended March 31, 2014. Participating in today's call will be Mark Siegel, Chairman; Andy Hendricks, Chief Executive Officer; and John Vollmer, Chief Financial Officer.

Again, just a quick reminder that statements made in the 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 EDGAR system.

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

Now it is 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 the first quarter of 2014. 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 March 31, and then I will turn the call over to Andy Hendricks, who will share some detailed comments on each segment's operational highlights, as well as our outlook. After Andy's comments, I will provide some closing remarks before turning the call over for questions.

Turning now to the first quarter, as set forth in our earnings press release issued this morning, we reported net income of $34.8 million, or $0.24 per share. Consolidated revenues for the first quarter were $678 million, and EBITDA was $206 million.

Our balance sheet is strong. We exited the first quarter with $258 million of cash and equivalents, and a conservative 13.4% net-debt-to-cap ratio.

Contract drilling performed well during the quarter, with increases in our average rig count, and average revenue per day exceeding our expectations. However, as previously announced, pressure pumping was challenged by the unusually severe weather during the first quarter.

Demand is strong for high-spec APEX, as we achieved better than 97% utilization of our rig fleet of APEX rigs during the first quarter. In fact, recently, demand for newbuilds surged further, such that all of the 20 newbuilds for this year are spoken for. Our next new-build availability is not until 2015.

Additionally, demand for our fleet of non-APEX rigs -- demand improved for our fleet of non-APEX electric rigs. In order to meet customers' current rig demand, we continued to activate non-APEX electric rigs during the quarter. Our non-APEX electric rig count increased on average three rigs in the fourth quarter and five rigs in the first quarter. We have an additional 12 non-APEX electric rigs in the US that could still be activated.

With the increase seen in US horizontal rig counts since last Summer, we believe that the industry has reached the point where high-spec land rigs are in short supply. Accordingly, we believe that the industry is at a point where, in previous cycles, day-rate increases accelerated.

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

Thanks, Mark. Following our typical format, I am going to start this morning with some commentary on our drilling business, and then finish with some comments on pressure pumping.

The appreciable increase in rig demand that first became apparent in the fourth quarter, continued through the first quarter. On average, our US rig count increased by 10 rigs, to 193 in the first quarter, from 183 in the fourth, which was better than we had expected. I am pleased to report that the rig count continues to grow, with the April rig count expected to average 199 rigs.

In Canada, our average rig count increased to 10 rigs from 9 in the fourth quarter. Drilling activity in Canada is being impacted by the Spring breakup, with our average rig count for April expected to be one rig.

Our average revenue per day increased in the first quarter by $210 to $23,380, from $23,170 in the fourth quarter, excluding the benefit from early termination revenues in the fourth quarter. Average operating costs per day increased $270 during the first quarter to $13,780, primarily due to rig-reactivation expenses, and also the typical first-quarter payroll taxes. The increase in average operating costs per day was largely offset by the higher-than-expected increase in average revenue per day. Our average margin per day was relatively unchanged, and better than expected, at $9,600 per day in the first quarter, when excluding the early termination revenues in the fourth quarter.

Looking forward, we expect demand to continue to improve, with our average rig count in the US expected to average 201 rigs in the second quarter. Our Canadian rig count is being impacted by the Spring breakup, and is expected to average around two rigs.

For the second quarter, we expect our average US margin per day will increase approximately $300 per day. With the changing geographic mix in the second quarter related to the seasonal decrease in Canadian activity, we expect our total second-quarter margin per day will increase by approximately $100, to $9,700.

Total revenue per day is expected to decrease to $23,100 due to the lower contribution from our higher-revenue Canadian rigs. This is expected to be more than offset by lower operating costs, which are expected to decrease to approximately $13,400.

We completed three new APEX rigs during the first quarter, bringing our APEX fleet at March 31 to 127 APEX rigs. We contracted an additional five new APEX rigs since our last conference call, including four to be completed in 2014, and one to be completed in 2015.

We have seen a surge in demand for new APEX rigs in the recent weeks, and are now effectively sold out of newbuilds through 2014. We expect to complete 20 rigs in 2014, and all either have signed contracts or are committed and awaiting signature by customers.

We will continue to build rigs to meet customer demand for high-spec APEX rigs, and we have added six more new APEX rigs in our construction program. We now expect to complete 23 rigs during the four quarters ending March 2015.

As of March 31, 2014, we had term contracts for drilling rigs providing for approximately $1.04 billion of future day-rate drilling revenue. Based on contracts currently in place, we expect to have an average of 137 rigs operating under term contracts during the second quarter, and an average of 111 rigs operating under term contracts during the remaining three quarters of this year.

Turning now to pressure pumping: As previously announced, our Appalachian operations were negatively impacted by unusually severe weather during the first quarter. This resulted in us having crews and equipment on location that were unable to provide revenue-generating services. Furthermore, while on location, we continued to incur labor, demurrage and other costs, including fuel costs to run our equipment in order to protect it in these extraordinary weather conditions.

The weather impact in the northeast was partially offset by improvement in the southwest, which benefited from increased activity in the Permian. Accordingly, while pressure-pumping revenues of $240 million fell short of our original expectation, revenues still increased sequentially from $234 million in the fourth quarter.

With the disruption in the northeast, gross margins as a percent of revenues decreased sequentially to 16.8%. We remain fundamentally positive on the outlook for pressure pumping with the increasing horizontal rig count. Increasing horizontal drilling activity, combined with greater frac intensity, is leading to higher demand for pressure-pumping services, particularly in the Permian Basin.

While we believe the industry continues to be oversupplied, however, with the increasing demand, the industry is moving toward equilibrium. As a result, and given our increasing utilization in our Texas operations, we have ordered sufficient equipment to create a 40,000-horsepower frac fleet that can be activated towards the end of the year.

For the second quarter, we expect pressure-pumping revenues will increase sequentially by approximately 10% to $265 million, and gross margins will return to approximately 21% of revenues. We continue to focus on differentiating ourselves in this business through excellent well-site execution, the introduction of new technologies, and the investment in new facilities.

We believe we are a leader in bi-fuel frac technology that uses natural gas as a fuel source. In the Marcellus, we have completed approximately 700 stages using natural gas as a fuel source.

As in drilling, we believe that natural gas bi-fuel is an important green technology, as it both reduces the environmental impact of our services and generates cost savings. With our bi-fuel fracking, it is able to cut diesel fuel consumption in half. Today, our bi-fuel frac units have replaced over 358,000 gallons of diesel with lower-cost and cleaner-burning natural gas, and thereby eliminated approximately 2.6 million pounds of transportation loads on local roads.

Before I turn the call back to Mark for his concluding remarks, let me provide an update on a couple of other Corporate financial matters. We expect to spend approximately $950 million of CapEx in 2014. We expect our effective tax rate to be approximately 32.7% in 2014. SG&A during the second quarter is expected to be $19 million. Depreciation expense during the second quarter is expected to be $152 million.

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

Thanks, Andy. Looking at industry rig data, the horizontal rig count bottomed last Summer, and has since increased by more than 150 rigs. Accordingly, we believe, substantially all of the high-spec rigs that were idled in 2012 and 2013 have now returned to work.

Looking at our own fleet, our existing APEX fleet is operating at effective full utilization, and all the new APEX rigs we are expecting to complete in 2014 are spoken for. Moreover, based on publicly available data and comments, it appears virtually all of the US industry high-spec rig fleet is taken up with commitments.

In our experience, day-rate increases accelerate when the industry reaches this point. And we think we are well positioned to take advantage of the expected increase in pricing, given our rigs in the spot market, and 77 rigs rolling off term contracts during the last three quarters of this year. With strong commodity prices and commensurate rig demand, we see a potential benefit in the remainder of the year as pricing responds to demand.

Our overall rig count, both APEX and non-APEX rigs, is likely to increase at a measured pace, given long lead items for new rigs, and the usual constraints for idle rigs going back to work. Perhaps most significantly, the strong customer demand continues to provide an impetus for us to continue retooling our fleet, which has substantially transformed our Company.

Turning to pressure pumping, the industry continues to be oversupplied. We believe, however, that demand for pressure-pumping services is likely to continue increasing, driven primarily by the more than 150-rig increase in the horizontal rig count since last Summer, together with further increases in horizontal drilling activity and frac intensity.

In essence, pressure pumping lags drilling, and we believe increases in drilling activity likely will drive future increases in pressure pumping. With this expected increase in demand, we see the industry moving toward equilibrium.

There is an additional reason for our optimism. The past year's very harsh and prolonged Winter has left natural gas in storage at the lowest level in 11 years. Gas prices reflect this level of storage. These higher natural gas prices provide our customers with increased cash flow, and provide the basis for further increases in oil-directed drilling and pressure-pumping services. Additionally, to overcome the shortage of gas, we may see increased natural gas drilling and pressure pumping later this year.

With that, I would like to both commend and thank the hard-working men and women who make up this Company, as it was their focus on the customer that helped to differentiate us. I am also pleased to announce today that the Company declared a quarterly cash dividend on its common stock of $0.10 per share, to be paid on June 26, 2014, to holders of record as of June 12, 2014.

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

Thank you.

(Operator Instructions)

The first question is from the line of Robin Shoemaker from Citigroup. Please go ahead.

Thank you. Andy, wanted to ask, in terms of -- you mentioned some upside in pricing for APEX type of rigs. How far are we below, you know, prior cycle, maybe, peak levels for spot and term contract rates? And would you anticipate that we gradually return to prior peak pricing levels?

Good morning, Robin. You know, that's an interesting question relative to peak and how far back you look to find a peak.

You know, I will tell you that our rig rates have remained steady, you know, through the last year. It is not that we saw a big dip in 2013, we were holding pricing for APEX, new builds, or pricing for the renegotiation of contracts, it may have been rolling. It all held steady for us through 2013, and as we entered 2014.

Because of that, we're very positive about the business. When it comes to some of the leading edge rates, and what that means versus spot and, relative to peaks, we don't really want to call out specific information for competitive reasons, but we are very encouraged.

We are sold out of new builds for 2014. And we believe there is a limited availability of high spec rigs in the US market, and we believe that the drilling rig rates will continue to improve.

If we look at what we said in the margin area, we stated that we are expecting that the US margins are going to increase by $300 per day from the first quarter to the second quarter. And so, if this strength continues in the third quarter, given the fact that we are already sold out of the new build rigs for 2014, and we can see that strength in the market, and with typical seasonal recovery in Canada, you know, we would expect to even achieve total drilling rig per margin dayrates increase by about $400 per day from Q2 to Q3.

Okay. So that is just the result of the, kind of, 77 rigs that are coming off contract repricing at slightly better levels. Understood.

So I was wondering also if you could speak about the cost pressures you may be experiencing. Of course, what we hear most about are shortages of labor and cost-related challenges in the Permian, where you have a very sizable presence. So I was wondering if you could talk about that and how you are managing through these cost pressures.

Sure. So that's a good question.

If you are a company that is a Permian-based company trying to operate in the Permian today and you are recruiting in the Permian, you are seeing challenges in trying to get people. If you are a company that works across North America and you have a recruiting effort like we do across North America, then you're less challenged, because your focus is you are not just trying to pull people from that Midland-Odessa area.

We recruit people from across the country. In fact, over the last year, half of the people that we recruited into drilling were active returning military. So we are getting a good population across the US; but with, you know, half of the individuals being active returning military, we are getting a very high quality of individuals coming into the system, working for Patterson-UTI.

So we are not seeing the same kind of pressures necessarily that you would see if you're a very Permian-focused company that's recruiting strictly in Texas or in West Texas. So we are not seeing those same kind of overall cost pressures that maybe some other companies are, especially when it comes to labor.

So like I said, that is why, if you look at our margins, going from Q1 to Q2 in the US, we expect that drilling margins are going to increase by $300 per day, because we will also be able to keep these costs in line, and I also -- because we are sold out of the new builds for 2014, spoke a little bit about what we might see in Q3. And if we see, you know, increase in rig rates further, this could further accelerate third quarter margins as well. They could be even a little bit better, because we will be holding our costs in line and, we are seeing a very strong market right now.

Robin, the thing I would just add to that answer also is that, we are not new to West Texas. The original Patterson comes out of West Texas.

We have been a strong business there, both on the drilling side and then recently through our acquisition through -- in the pressure- pumping business, with home-grown businesses that have a long and distinguished history there. So, for us, recruiting in those markets is a little different, I think, than for some of the new players who just entered the market.

Okay. Thanks for that.

Next question is from the line of Byron Pope from Tudor, Pickering, Holt. Please go ahead.

Good morning, guys. Just on the rig side of the business, the constructive dayrate commentary, it sounds as though, based on how you are framing that incremental fleet average daily cash margins, that that will benefit the non-APEX electric rigs as well. But is that almost across basins as opposed to just the Permian?

Yes, I would say it is equally across basins. You know, we have seen rates move up on APEX. We have seen rates move up on the non-APEX electrics as well.

Mechanicals have been holding steady right now, but as activity increases in 2014, we will see how that level of rig class moves as well. But I would say that is across basins.

Okay. And then on the pressure pumping side, excuse me if I missed this, but the 40,000-horsepower that is being added, will that be bi-fuel capable?

It certainly has the potential to be bi-fuel capable. We also have bi-fuel kits on in order, so we will determine if we need to add those kits to that fleet.

Okay. And given the deployment will be late this year, I am assuming how constructively you are framing the pressure-pumping market, it is still up in the air as to whether or not that will be deployed in the Southwest as opposed to the Northeast.

We are going to be focusing that on the markets in Texas. That is where we are seeing the strongest increase in activities. We are very positive about the business overall. We did state that we believe that it is over-supplied right now, but let's look at the macro.

Patterson-UTI drilling has sold out of new APEX rigs in 2014. The industry has increased the horizontal rig count by approximately 150 rigs since the low of 2013. And if you look at the new builds in 2014, the industry is putting out about 80 to 100 new builds across 2014.

So you have got increasing horizontal activity. We have got increasing frac intensity, especially in the Permian, where you are moving some from vertical to horizontal. And so this is just going to lead to a steady increase in pressure pumping utilization throughout 2014 and into 2015.

And this is why, you know, we are certainly encouraged to go ahead and order this 40,000-horsepower. We expect that this will be activated sometime around the end of 2014.

Great. Thank you. Appreciate it.

Next question is from the line of Jason Wangler from Wunderlich Securities. Please go ahead.

Good morning, guys. Curious, on the drilling side, you talked a bit, obviously, about gas prices doing better and the inventories and things.

Have you started to hear much rumblings as far as the inquiries moving something out and some of those less active gas basins, or maybe even being able to run some rigs that way? I think you mentioned a few rigs that you have gotten the last few months that were non-APEX.

I think you are putting together two things. We have seen some increases in activity in our non-APEX rig fleet. So that is one point.

And we have also seen a few, but there are very few, inquiries about rigs going to work for natural gas. So we have seen just a little of that.

Obviously, we are all conscious of the fact that we are at this very low storage level. We are also at this very low gas rig level.

So, one starts to think that that is a very interesting possibility for later half of the year, or into 2015. Not seeing a lot of activity now, but typically customers take a while to react to these sorts of things.

We just had the harsh winter, kind of, continuing even into April. And so, you know, if you expect it to take sometime for people to respond, we are not really surprised by the fact that they haven't already responded, but think that is, possibly, a second half of the year event.

Sure. And then, curious, on the pressure pumping side, specifically up in Appalachia, obviously, the weather was very tough, and that is understandable. But we have heard in other basins that the tough weather wasn't as harsh on drilling, and, obviously, you guys would know that very well.

Is there a big backlog of wells or, you know, maybe an inflated backlog of wells, that the completion work just wasn't done on, as there was a lot of drilling going on; but, like you were saying, the completions just couldn't go off because of the weather? Is that maybe a little bit higher than you expected going into the second quarter? Maybe there is going to be some catch-up to be played in that region that may be helpful as we go throughout the year?

Drilling activity stayed relatively busy through the winter season, especially since you have seen this increase in pad drilling over the last few years. We are not having to move rigs as often from pad to pad.

But at the same time, I wouldn't say that for us there is a big backlog of wells. I would say that our calendars are starting to fill out, and we are certainly encouraged, especially after the harsh weather that we saw in Q1 up in the Northeast.

And so that is why, you know, we are saying that our margins are going to be back in that 21% range. But I wouldn't say it is a big backlog, but I would say that the calendar is filling out.

That is helpful. I appreciate it.

The next question is from the line of Marshall Adkins from Raymond James. Please go ahead.

Marshall?

Can you all hear me?

Marshall?

Yes.

There we go.

Mark, you mentioned the Permian. I know you have a dominant position there historically.

Help us understand, do you have -- is there a competitive advantage you have being there? And, I know you don't think about it in these terms, but what percent of your business is there now; and recognizing that most your assets are on wheels when they actually move, where do you see that going?

I will let Andy take the first shot at it.

Is this in reference to drilling or pressure pumping?

Yes. Both.

You know, about 25% of our drilling business is in West Texas across the Permian and into New Mexico. Very excited about our position there.

We have multiple facilities to support that operation in West Texas, and back to the challenges and people that you might be hearing from some others, we are recruiting nationally to bring people into the Permian. So we are not seeing necessarily maybe some of the challenges to get people crewed up on rigs over there.

So we are very encouraged by the increasing activity levels in the Permian. We are encouraged by the increasing rig count, especially around horizontal drilling in the Permian. And that kind of moves on to our pressure pumping story.

We are upbeat about this business. We think that utilization will continue to improve steadily throughout the year.

And when you look at how we are positioned in West Texas Permian, we have multiple facilities. We are running not just hydraulic fracturing, but cementing and other services across the basin.

We have, probably, one of the most comprehensive lab facilities in West Texas. So we can do chemistry testing right there in Midland, doesn't have to go other places for testing, and we do it in-house. We are running cementing lab testing 24 hours a day to support our operations there. So when it comes to the Permian, we are in good shape.

Let's shift gears a little bit. The rig reactivations, I would guess being in the Permian may help those. But of those, I think, Mark, you mentioned 10 more additional ones, that you're -- electric rigs that you could reactivate.

What are the prospects for those, number one? Number two, should we be concerned about the -- as you reactivate the costs that come into the system, are you kind of already planning for that?

You know, Marshall, the number is 12. And the answer to the question is that, frankly, what will spur us on to activate those rigs is the same thing that spurred us on to activate the ones that we put out so far; which is that the customer is willing to pay a dayrate that, in effect takes into account whatever the costs of reactivations are, and gives us terms that, we believe, will enable us to, in effec,t make a good return on our investment if we need any.

So we are very conscious of that. Frankly, one of the very good things about the upcoming quarters is we have some significant flow of new rigs coming forward in the marketplace the next two quarters, and so we are feeling pretty bullish about that element.

Perfect. Last question for me.

The 40,000-horsepower, you mentioned that you are seeing enough to get that going. Is that all incremental, kind of, new builds, or is that part of what you had before and part new?

No, that will be completely incremental new build. Everything that we have today is out working somewhere. So this will be incremental.

Perfect. Thanks, guys.

Thank you. The next question is from the line of Waqar Syed. Please go ahead.

Hello, Waqar.

Can you hear me?

Very well, sir.

Great, great. Given that you are already sold out for your new builds for the remainder of the year, if you were to choose, could you increase the cadence of the rigs that you -- new build rigs that you can supply to the market in 2014?

You know, in 2014, that might be a little bit difficult. Everything is working off long-lead items. It is why we have increased the number of rigs that we are going to build going into 2015.

So I wouldn't necessarily expect us to increase for 2014. However, if you look at the upside, and the total number of rigs we have out working today, we have 137 rigs that are on contract.

If you look at it, in Q2, we have about an average of about 64 that are on spot. And what you will see is opportunities on some of these to move upwards as we progress in 2014 with the increasing rig rates.

Sure. Now, what is the main item that is in -- the lead times are longer? Is it just the top drive, or are there other items as well where the queue is long, wait times are long for ordering?

I would say top drives, AC-control drive systems, but I wouldn't say necessarily that lead times have extended. It is just that they remain steadily long on those bigger items.

Okay, okay. Now, in terms of the leading-edge dayrates, you seem to be very positive there. Could you quantify to us, kind of, a range of increases that you are seeing there?

Well, back to what I was saying earlier, for competitive reasons, we don't really want to call out a number or a range. I would like to take you back to a discussion around what we see the margin doing.

So, as we stated, we expect that the margin is going to go up by $300 per day in the US from Q1 to Q2. If we look for it even to Q3, if you add in Canada, the total drilling margin per day will have an increase of approximately $400 per day, and if the increase in rig rates further accelerates then third quarter margins could even be better.

Great. Now, would you hazard a guess as to what the total industry-wide rig count increase could be by the end of the year from where we stand today, based on what you are seeing or hearing from your customers?

I think it is difficult to actually predict what that total increase is going to look like. Certainly on the new builds, we are seeing about 80 to 100 new builds come to the market.

What has also been interesting for us, at the same time, is, we have been holding steady on a non-APEX -- well, holding steady, we actually increased, our non-APEX electric and mechanical rig count. I think there was some concern that as we put out new builds, that some of these rigs might drop in the count, but that has not been the case. We have actually increased the non-APEX electrics and the mechanicals.

Okay. Great.

Thank you very much. That is all I have.

Thank you The next question is from the line of John Daniel from Simmons. Please go ahead.

Thank you. Andy, the topline guidance for pressure pumping seems a bit light when you consider that the guidance for Q1 was originally $260 million. I would assume that the original Q1 guidance at that point factored in some weather days, just given a few of the frac calendars are probably more robust in Q2 than Q1. Can you just comment on why, and some thoughts on the color for the guidance?

Yes, Q1 was a bit challenging with the weather. As we get into Q2, we still had some winter that kind of spilled into April at the same time, but we are starting to fill out the calendars again.

The Northeast is getting back on its feet. That is why we are encouraged that the margins will get back to 21%. But we are seeing the calendar start to fill out again.

Okay. In addition to the 40,000-horsepower, is there any other horsepower that is on order at this point?

No.

Any plans to retire old stock horsepower this year?

No. You know, the horsepower that we have -- and maybe this is in the context of, is equipment wearing out, or something was referenced to that. We are just not seeing that.

When you look at a pressure-pumping company like ourselves that -- one of the top tier, and, certainly, a very well-performing pressure-pumping operation, we continue to invest maintenance capital; and you see us manage the M&S budget around that to where we are continually maintaining that equipment. And we are not seeing equipment wear out in that horsepower class range.

If we were to retire any horsepower later in the year, it might be because it is just smaller, older pumps that just aren't capable of horizontal fracking. But certainly nothing to do with equipment wearing out.

Okay. Are you -- how often -- what is the cycle time from when you rebuild the equipment? 10,000 hours? Do you have a set time?

It is not a set time on a pump package. You have got different hours on an engine, different hours on a transmission, different hours on the pump.

Okay. Fair enough. Last one -- well, two quick ones.

One, full-year expectations for depreciation, if possible? And then second, have you guys updated or published a new price book for your pressure pumping segment yet? And if not, do you intend to do it any time soon?

John is looking up the depreciation number.

Yes, current estimate's about $615 million for the year.

Okay.

When it comes to pricing in pressure pumping, we haven't published a new pricing book. We have been actively, you know, trying to push pricing up in Q1.

We had a few successes, but in general, I would say it is not moving up, you know, overall. I would say, it, certainly, has stabilized; and we will just see how that success continues as we continue to increase utilization as we work through 2014.

Okay. Thanks for taking my call.

Thank you.

Thank you. The next question is from the line of Jim Wicklund from Credit Suisse. Please go ahead.

Better late than never.

Hey, Jim.

Good morning, guys. Considering the strength that you see in the drilling market today, in an existing rig, not a new build, but an existing rig, would you rather have it on contract if it rolled off, or keep it on spot?

It depends on what the pricing is, Jim. I mean, you know--

That's why I am asking you the question.

The price on the term, Jim. We are -- as you well know, there is a number of financial people here at Patterson-UTI who spend a lot of time thinking about those exact questions. And we are frankly trying to figure out the rate of incline right now.

Frankly, we started the year 2014 thinking that it was going to be a good growth year. We have seen this surge in demand toward the end -- toward the beginning -- middle of April, and we are looking at that, and thinking about, you know, how to take in -- what it means for the rest of the year.

Frankly, it is just a little hard to telescope further down the road, because just what we have seen now, it looks pretty positive. Trying to figure out the rate of increase.

Surge in demand usually puts the focus on the spot market historically, right?

It does. So as you can imagine, we have got a few operators that are trying to lock us into some long-term contracts and have that optionality for themselves. But for us to do that for them, they are going to have to sign a rate that is higher than spot today.

So you would say that you have -- you are more of a price -- you are not as much a price taker as you have been in the past, is that fair?

I would say we are still a price taker, but we are trying to make sure the optionality is on our side as opposed to theirs.

Fair enough. Second question, if I could.

RPC yesterday announced they were adding horsepower; you guys are announcing you are adding horsepower. I am assuming this is in part because you can, and other people can't, and that kind of assures you of expanded market share down the road. Is that fair?

Jim, I would say that the prevailing reason for making this decision is -- are two-fold. One is that, the point we have made before, which is that we have seen this increase in drilling, and we believe that pressure pumping logically follows; and so we see that sort of coming about as the year progresses.

And the second thing is that any number of our customers are speaking to us about increased needs for frac crews, and we don't want to be in a situation with our crews, pretty much, spoken for, that we are unable to meet those demands. And so the view is that we needed to have this additional rig -- frac fleet, at least in the pipeline, so that we would be able to meet some of that expected demand.

Okay, and my last question, if I could. Two of the big three announced they were gaining market share in pressure pumping, the third said they were holding steady. So it was obvious that it is those other people who are losing share, but we can't figure out who those other people are.

You are adding capacity, so it wouldn't seem like you are losing share. Who is losing share in this market?

You know, that is a good question. This is, you know, this is a market that still has over 50 different players across the lower 48.

We are up in the Northeast and we're in Texas. Makes it a little bit more challenging for us to call a US market share number; but we are certainly confident in our position and ability to deliver. That is why we've ordered the other 40,000-horsepower.

Jim, we saw a huge number of entrants into this business financed by private equity. It is hard for us to know how those companies are all doing because most of them are private and don't report.

Okay. That kind of answers the question. So I appreciate it, guys. Thank you.

Next question is from the line of Pete [Niur] from RBC. Please go ahead.

Hey, everybody. It is Kurt, Kurt Hallead here. How are you?

Good morning, Kurt.

It's not Pete. Pete is my cohort. We have been overlapping calls as you know today.

So, caught -- did most of the Q&A session, but not your prepared commentary. I want to follow on to Jim's line of questioning, which is there seems to be some consensus view that the excess capacity in frac, market-wide, is now down around 10% versus maybe the prior commentary, which would indicate around 15%.

So that is, supposedly, idle capacity available to the marketplace. We have heard from you and a couple other players that they will be adding capacity to the market. You indicated that you're adding capacity to have it available should you get a call.

So, I guess, you can imagine why I am scratching my head. It's like, why would they need to call on Patterson or anybody else when there is 10% available capacity still in the marketplace?

Well, frankly--

That is just, kind of a -- I would like to get your thought on that. But the bigger question is, as an industry, and we are just getting back to the point where you guys can really start to lever pricing, and now you are adding capacity on top of that?

To me, that doesn't really bode well. So what's your take on that?

Well, the first point is that we are not waiting for the customers to call us. Customers have been in active discussions with us about their expectations of needing additional frac fleets. So quite frankly, we are uncertain, as the business increases, whether we are going to be able to meet the demand for their needs, but, at least, having an additional fleet on order will at least assist us in that.

So, you make it sound extremely speculative. I don't see it as speculative the way you put it. That is the first point.

Second, what we are saying, and I guess I haven't made this -- we haven't made this clear enough, is that with more than 150 rigs having gone back into the marketplace since last summer, we see a substantial increase in the number of wells being drilled; and therefore, a substantial increase expected in the number of wells that will need to be fracked. Add to that, increasing frac intensity, and we think that the market will be reaching equilibrium.

Yes, we think that there will be some better pricing, we have said that. But, we also think that our position and the margins we have been able to achieve, have been pretty impressive over the many years we have been in the business.

We have not been one of those players who has operated at the smallest, leanest margins. We have been one of the least expensive operators trying to say we price the most aggressively.

Okay. Thanks.

And I guess, my take on it then is there probably isn't 10% spare capacity if you and others are adding it and you are getting inquiries from customers, because I am sure if they call around and they ask, and if it were available, they would be using it; and they wouldn't be asking you to help them out. So maybe we are not even at 10% capacity.

Yes, since we're not in every market in the US, it is hard for us to put a number on exactly how much spare capacity is out there. But certainly, if you focus on the Permian, that market is getting tighter.

We expect that many of the frac fleets in the Permian all had some kind of work within the last month or so, based on our estimates. And we expect activity to continue to improve in the Permian.

So we need to have that 40,000-horsepower towards the end of the year. We were actively trying to push pricing in Q1 to see how much success we could get. We had a few small successes, and we will continue to actively try to push pricing.

We don't know how that is going to look yet, but there is no question when you get back to the macro of the number of rigs that are coming into the market in total across the US, and especially in the Permian, you know, horizontal drilling activity is increasing. The frac intensity is increasing. The number of stages per month continues to grow in the industry, and we are going to get to equilibrium in pressure pumping.

What is a price per horsepower that you are paying for this new -- for this crew?

We pick it up, in general, for less than $1,000 new.

Okay. Then lastly, can you give us an update on your thoughts on expanding internationally, in any context to that?

I guess I will ask it in a tongue-in-cheek way, why you still have rigs in Canada?

(Laughter.) We think Canada, for us, is still a long-term good market. The interesting thing about the rigs that we run in Canada, we typically run the triple rigs.

We are drilling horizontal wells with triple rigs in the plays like the Montney and the Duvernay today, which are the plays that we will be exporting natural gas through the LNG systems off the West Coast. So we are very happy to be in those plays. We think long-term, we are going to have opportunities in Canada, so it is still a core part of our business.

Outside of Canada, what is your thought on -- what is your update on your thoughts on where you might go?

No real update. We have called out that we are pursuing international opportunities organically. It is not anything that is going to be meaningful in 2014, and it is just going to take time to put all that together.

All right. Thanks.

Thanks.

Next question is from the line of Brad Handler from Jefferies. Please go ahead.

Hi, guys. I am sort of laughing at myself before I ask this question because I was listening to Kurt's question, and I guess I am going to come at this -- I was planning on coming at this from the very opposite standpoint, so you guys can decide which vantage point you want. My question was going to be and still is, why are you only ordering 40,000-horsepower?

So now you see why I am laughing. But the reason I ask it from that vantage point is, you basically are adding one crew, and maybe a little bit of spare, I guess.

But, given this very robust outlook that you are outlining, and I am sure you feel like you have more than one customer opportunity that is lining up, why not put forward a little bit more spare capacity? I mean, 6%, one crew, just not a lot, right? Why aren't you, if you will allow me to ask it this way, by approaching it a bit more aggressively?

You know, I think -- let me just start by saying we are very positive about the pressure-pumping business. Back to the macro that we discuss, we see increasing utilization steadily throughout 2014.

There is some lead time on the equipment. Could we order more than 40,000-horsepower? Yes.

I think we're still cautious, though. We still see some oversupply today. We see that that is going to work towards equilibrium.

I think it is hard to know exactly how fast it is going to get to equilibrium. If we want to add more capacity later, I certainly think that we will have that option with our Board of Directors. But right now, we have just got 40,000-horsepower on order. Mark?

I guess I would just add, responding, it is a measured approach. It is interesting to realize that on the same call, within the same few minutes, that one view says we have ordered too much and one can take the view that says we have ordered too little.

You know, obviously Management and the Board spends a fair amount of time trying to make the right judgments about how to allocate capital. We think that over the years, we have been pretty successful at doing that.

We think this is a good judgment call about how much capital to allocate, and recognize that we think that we could increase it if we think later on that we have underallocated or, you know, in effect been careful with it before. Historically, we have been able to achieve good margins in pressure pumping, and expect to continue to do that.

Yes, that is a fair answer, and it makes sense. If you chose to order more, could you still get it by year end, as your sense of the capacity in the marketplace?

Depending on the timing, it would be close.

Okay. Okay.

Considering we have been buying new equipment off and on for over a year, we are a pretty good customer for suppliers.

Right, right. Fair enough.

That is it for me, guys. Thanks.

Thank you. Your next question is from the line of James Schumm from Cowen. Please go ahead.

Hi. Good morning.

So you mentioned potentially 80 to 100 new builds this year and high spec rigs are seeing utilization rates north of 95%. So is this current level of building enough to knock those utilization rates down a bit by the end of the year, or what are your thoughts on that?

So, as an industry, we see about 80 to 100 new high spec rigs coming into the market throughout 2014. Our APEX utilization right now is at 97%.

So we don't see that number of rigs is going to decrease overall utilization at the end of 2014 or even early 2015. That is why we have had to increase the amount of rigs that we are building in the program, and added six more rigs.

Okay. And then, sorry if I missed this, but in pressure pumping, are you seeing any cost increases with respect to sand or other materials?

You know, the winter in Q1 really took its toll in a lot of areas. Some of it had to do with, you know, sand cleaning at the mines, transportation of sand to certain basins.

We have seen some increases. Not sure if that is really going to hold out through the rest of the year. As we get past the effects of the winter in Q1, that may start to level out. We will just have to see how it goes.

Okay, great. Thanks. That is it for me.

We have no further questions on the telephone at this time.

Well, I would like to thank everyone for joining us on this call and look forward to speaking with everyone as we report our results at the end of the second quarter. Thanks, everybody.

Thank you for your participation in today's conference. This concludes the presentation.

You may now disconnect. Have a very good day.