Patterson-UTI Energy Inc (PTEN) 2012 Q2 法說會逐字稿

Good day, ladies and gentlemen. Welcome to the Q2 2012 Patterson-UTI Energy Incorporated earnings conference call. My name is Cheverly, and I'll be your operator for today. At this time, all participants are in listen-only mode. Later we will conduct a question-and-answer session. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Mr. Mike Drickamer, Director of Investor Relations. Please proceed, sir.

Thank you, Cheverly. Good morning, and on behalf of Patterson-UTI, I'd like to welcome you to today's conference call to discuss the results for the three and six months ended June 30, 2012. Participating on the call today will be Mark Siegel, Chairman; Doug Wall, President and Chief Executive Officer; Andy Hendrix, Chief Operating Officer; and John Vollmer, Chief Financial Officer. Again, just a quick reminder that statements made in this conference call which state the Company's or Management's intentions, beliefs, expectations or predictions for the future are forward-looking statements. It's important to note that actual results could differ materially from those discussed in forward-looking statements.

Important factors that could cause actual results to differ materially include, but are not limited to, deterioration of global economic conditions; declines in customer spending and in oil and natural gas prices that could adversely affect demand for the Company's services, and their associated effect on rates, utilization, margins and planned capital expenditures; excess availability of land drilling rigs and pressure pumping equipment including as a result of reactivation or construction; adverse industry conditions; adverse credit and equity market conditions, difficulty in integrating acquisitions; shortages of labor, equipment, supplies, and materials; supplier issues; weather; loss of key customers; liabilities from operations; government regulation; and ability to retain Management and field personnel.

Additional information concerning factors that could cause actual results to differ materially from those in the forward-looking statements is contained from time to time in the Company's SEC filings, which may be obtained by contacting the Company or the SEC. These filings are also available through the Company's website and through the SEC EDGAR system. The Company undertakes no obligation to publicly update or revise any forward-looking statement. 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.com 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 the second quarter of 2012. We are pleased that you're able to join us today. As is customary, I will start by briefly reviewing the financial results for the quarter ended June 30. Then I will turn the call over to Doug Wall, who will share some detailed comments on each segment's operational highlights as well as our outlook. After Doug, Andy Hendricks, who recently joined the Company as Chief Operating Officer, will share some of his thoughts, and then I will provide some closing remarks before turning the call over for questions.

Turning now to the second quarter, as set forth in our earnings press release issued this morning, we reported net income of $92.5 million, or $0.60 per share, for the second quarter ended June 30, 2012; and $190 million, or $1.22, for the six months ended June 30. EBITDA for the quarter was $279 million. The financial results for the second quarter include a pre-tax gain of $27 million, or $0.11 per share, related to the previously announced sale of our flowback operations and the auction sale of certain excess drilling assets.

I'd like to start by saying that in the face of difficult market conditions, both of our core businesses performed well. In the case of drilling, average US rigs operating and average margin per operating day were near our expectations; which was a significant accomplishment as rigs move from natural gas regions to oil and liquids regions and as decreasing oil prices caused customers to change plans with increased frequency. In the case of pressure pumping, performance exceeded our expectations. Revenues declined by 15%, which was actually a lesser decline than we had expected, and EBITDA declined by only 10% helped by cost controls which we had implemented.

These accomplishments in operations were mirrored in three noteworthy achievements on the financial side. First, we sold our flowback business for $42.5 million. Second, we issued and sold $300 million of 10-year 4.27% notes. And third, we completed share repurchases of more than 3% of our Company's outstanding stock. In respect to the buyback, we saw an opportunity to capitalize on our undervalued stock and to use effectively the proceeds from the sales of flowback operations and other excess drilling assets. This repurchase was a conducted under our previous share repurchase authorization.

Today, I'm pleased to announce that our Board of Directors has increased the share buyback program to $150 million. Our balance sheet remains strong, and following the debt issuance, our debt-to-total capitalization ratio is only 19%. I will now turn the call over to Doug.

Thank, Mark. Let me start this morning with some commentary on our drilling business. Despite all the moving pieces, the contract drilling segment of our business has held up nicely. For the quarter, revenues within this segment were $460 million. In the US, revenues increased $4 million sequentially, while in Canada, revenues decreased by some $33 million. Total operating days were down 6%, as the prolonged breakup in Canada resulted in an average of less than one active rig in this market for the quarter. In the US, our activity levels remain strong, and although we have seen some softness in certain markets throughout the quarter. At the end of the second quarter, we had six rigs under term contract that were on standby rate.

For lack of a better word, I'm going to characterize the US contract drilling market as choppy. In addition to low natural gas prices, during the second quarter, we began to see some concern over oil prices, a lower sense of urgency in getting things done by our customers, and a greater number of idle days between contract. All of these things combined to have a negative effect on our average rig count. In Canada, spring breakup was prolonged by wet weather, which made it difficult to move equipment. Activity is finally starting to pick back up, and we now have five rigs working in this market.

While one might expect that the changes in the US market would have had a negative impact on day rates, during the second quarter, our average revenue per operating day in the US increased by $270 to $22,480. While pricing and dry gas markets is certainly more competitive, our ability to move rigs to the oily markets and the impact of new builds has kept our pricing up. The market churn in the US, however, did impact our average US daily operating cost which, increased by $440 per day to $13,170.

This increase is largely due to costs associated with crews performing additional maintenance on rigs during down time between contracts and some incremental costs associated with moving rigs to different regions. During the quarter, six rigs moved from one region to another, all at the customers' expense. Over the first six months of this year, we have had 17 rigs get repositioned from dry gas markets to oily markets. Although the pace has slowed, we are still seeing this movement from region to region, and it certainly has contributed to the higher average daily cost.

Looking forward, there's a fair amount of uncertainty in the market. With fluctuating commodity prices, operators do not seem to have a lot of urgency to act one way or another. Accordingly, we expect market conditions to remain choppy during the third quarter. We should benefit from the seasonal recovery in Canadian activity, but that will likely be offset by a somewhat lower US rig count. For the third quarter, we expect to average 222 rigs operating, including 215 in the US and 7 in Canada. Included in this outlook for 222 operating rigs are 7 rigs that we expect to be on standby. These rigs will generate operating days, but typically earn a discounted day rate and will incur minimal costs as they do not have crews.

Considering the impact of these stand-by rigs on our average daily revenue and operating cost for the third quarter, we expect our overall average daily revenue will decrease by approximately $300 per day; however, we expect our gross margins on a per-day basis to be approximately flat. Our total term contract backlog is now estimated at $1.5 billion. Based on contracts currently in place, we expect to average 141 rigs under term contract in the third quarter and an average of 131 rigs during the last half of this year.

In terms of our new build program, we completed four new APEX rigs during the second quarter. In addition, we signed two term contracts for new APEX rigs during the quarter and now have 17 of our APEX rigs contracted out of the 24 new builds scheduled for this year. As previously mentioned, the demand for rigs under long-term contract has certainly slowed. Nonetheless, we remain confident in the demand for advanced technology rigs and the returns to be achieved from building these rigs.

On the subject of new APEX rigs, I would be remiss if I did not point out that during the second quarter, we reached the significant milestone of 100 new APEX rigs in our fleet. I want to take this opportunity to personally thank everyone involved in our engineering and our rig manufacturing efforts as your work continues to position this Company to meet the future challenges of the energy industry.

Turning now to the pressure pumping business, under the circumstances, we had a better quarter than we expected, but this market continues to be difficult. Revenues in this segment decreased 15% sequentially to $206 million, better than the 20% decline we had expected. EBITDA fell 10% to $63.8 million. Lower proppant sales due to customer mix, lower utilization, some price erosion, as well as the sale of our flowback operations negatively impacted revenues for the quarter. However, I am pleased to say that our frac activity levels and the number of stages completed were actually higher than we expected. Based on market conditions, we implemented some additional cost containment programs which helped us generate EBITDA margins of 31%, actually up from 29% the first quarter.

Across the pressure pumping industry, pricing has softened given the excess capacity we see in all markets. We will continue to work towards keeping our crews busy, but as I've said before, we don't need the practice. We will continue to push for profitable work. I'm pleased that our proven performance, our high quality equipment, and our established infrastructure has allowed us to maintain reasonable utilization levels and to continue to work profitably. [Any] operators still describe value for a demonstrated ability to get the job done in a safe and efficient manner.

An increasing part of being able to get the job done is the logistics associated with the sourcing of raw materials and delivering them to the well site on time. We have established the infrastructure necessary to handle many of these challenges that negatively impacted our competitors. I want to once again commend our supply chain team who allowed us to side step the shortage of the day, this quarter of course being guar. Our exposure to guar is relatively limited as we use very little of it in the northeast market. We were able to build a sufficient inventory for our southwest operations, and we remain comfortable with these inventory levels.

We do still have some further deliveries of new equipment scheduled for the third quarter from orders we placed a year ago. As we mentioned in our last call, the bulk of this equipment delivered in the second and the third quarters will be parked in one of our yards until such time as demand improves. Let me finish up this morning with some expectations for the third quarter for pressure pumping. The challenges in this business that I outlined earlier will certainly have an impact on our activity levels and earnings in the third quarter. Based on what our customers are currently telling us about their plans for the quarter, we expect our revenues in this business to fall by approximately 10% sequentially. With respect to gross margin, we expect a decline of approximately 300 basis points to approximately 30%.

Before I turn the call over to Andy, a couple of other financial comments. We currently expect SG&A for the quarter to be approximately $17 million. We expect full-year 2012 depreciation of $520 million, including $132 million in the third quarter. Full-year 2012 CapEx is still expected to be approximately $1 billion. So with that, I'll now turn the call over to Andy for some of his thoughts on what he's seen so far.

Thanks, Doug. First, I'd like to tell everyone how pleased I am to be on and participating in the call this morning. I've been with the Company a relatively short amount of time, and I've used much of this time traveling to the field to see our operations firsthand, meeting the people on our team and visiting the customers. And I'm quite pleased with what I've seen so far.

Our employees in the field are highly skill and well trained, and they're supported by strong leadership teams in various regions. Most importantly, everyone is working hard to execute the operations safely. And when you're out there, you can see the clean rigs and the well-organized frac locations and that everyone takes pride in what they do. And this shows in the high level of service quality that they deliver to our customers. For those at Patterson-UTI who are on the call today, I would like to thank you for the strong foundation that you've laid out for this Company and for the warm welcome that I've received since joining and traveling to facilities and well sites.

The other exciting part for me is knowing that our people have leading-edge technology to work with, whether it's one of our AC drive APEX1500 rigs with the latest control systems for maximizing drilling rates or an on-the-fly dry gel blending system for fracking operations that reduces dependency on liquid gels. Our people have some of the newest and most advanced equipment in the field. This makes for a great combination in providing top service quality to our customers.

And while I've known many of our customers for years, its been nice to see where Patterson-UTI's many longstanding relationships with our customers. We work together through the ups and downs of the energy cycles, and it's these strong relationships, especially at the field level, which leaves us well positioned to manage our business through these troughs and going forward.

These aspects all reflect positively on the Patterson-UTI leadership team and their efforts to serve the customers, employees, and shareholders. I came to this Company because of the great opportunities that we all have here, and after seeing operations firsthand, I'm even more certain of this. So I look forward to carrying on with the initiatives that the team has started and the bright future that lies ahead. And for those of you on the call this morning I look forward to getting to know many of you during the near future, thank you. Mark?

Thanks, Andy. During the second quarter, there was a significant amount of change in market conditions to which we had to adapt. At the time of our last call, there was substantial optimism about drilling completion activity in the oil and liquids rich areas. There was also considerable pessimism surrounding the prospects for the natural gas markets. For this reason, we were prepared for and, in fact, did see the continued rebalancing of the rig fleet between oil and gas markets. However, as the quarter unfolded, oil prices declined, and more importantly, our customers became more concerned about the direction of oil prices, especially as increased inner-day oil price volatility heightened price concerns.

In turn, operators took an increasingly cautious outlook towards long-term capital commitments for oil projects as industry participants tried to assess the complex array of factors determining oil prices. Faced with these changing market conditions, our drilling and pressure pumping operations both had successful operating quarters, reflecting our strong ability to adapt quickly to fast-changing circumstances in both oil and gas markets. Equipment and labor were moved efficiently between customers and regions with only minimal losses of revenue.

Our operational successes were complemented by the financial transactions we also completed during the quarter, including the sales of non-core assets, the repurchase of more than 3% of our Company stock, and the previously announced private placement of $300 million of senior notes. The result of these operational and financial achievements increased our financial flexibility and strengthened our balance sheet so that at June 30, 2012, we had $75.3 million in cash and $360 million available under our revolving credit facility.

Our strong operational and financial flexibility provides a base upon which to build shareholder value. We will continue to weigh opportunistic share repurchases, acquisitions, and the further improvement of both our drilling and pressure pumping fleets by capital expenditures -- all in order to seek the best returns for our shareholders. Although we expect to see a continued decline in activity levels and a downward pricing pressure in the third quarter, we are encouraged that with oil prices back near $90 and with natural gas prices above $3, far better than the sub $2 price that had been widely predicted for the end of summer, these trends are starting to moderate. We see some customers start to consider modest increases in their drilling and fracking programs.

Finally I'm pleased to announced today the Company declared a quarterly cash dividend on its common stock of $0.05 per share to be paid on September 28, 2012 to holders of record as of September 14, 2012. Let me conclude by thanking the men and women of Patterson-UTI. Operator, we would now like to open the call to questions.

(Operator Instructions) Your first question will come from the line of Kurt Hallead representing RBC. Please proceed.

I had a question on -- the question I had for you was on your last comment there, Mark, about customers starting to talk about increase in drilling programs. Obviously, a very maybe encouraging note among what has been a sea of information that would suggest that most of your competitors and some of the service companies are suggesting otherwise. So I'm just curious as to maybe what is unique about these customers that are indicating an increase in activity in your history. Have you seen these customers in the past be the forefront of some of the shifts in the business? And can we actually as a group here take that commentary as a potential indication that the bottom is closer, and we're going to start to see a turn? So whatever color you can provide would be great, because we're just now picking up on any of that from the companies that we talked to so far.

Kurt, it's always a challenge as you know to decide what direction the market is heading in. But we certainly have seen our two sets of customers. When oil prices were around $80 and potentially looking like they could go lower than $80, there was a huge amount of fear and concern that was provoked. As the price of oil got to $90 and it stayed around $90, and it looked a little more secure in that area, inquiries by customers for oil projects increased.

Similarly, the same thing occurring with projects in the natural gas area as the price went, as you know, from under $2 for a brief moment to near $3 or above $3 actually. So we're seeing these customers saying to us, look we may need some additional rigs either end of the year or the beginning of next year. Can you talk to us about what availability you would have, and we're engaged in those conversations. Whether those customers are trend leaders or exceptions is hard for us to know. There's just no way for me to really do much except to report that we're having those conversations. We're encouraged by those conversations. We're hopeful that it reflects a trend, but it's way too early for us to call it one.

And then just in that context of that question too, from a customer mix, can you help remind us, can you remind us both in terms of your drilling and your frac operations, how you would strike it down between major integrated oil companies versus large ENP and small ENP?

I think I'll let John do that, Kurt.

Overall, we've seen a shift in our business, Kurt, over the last several years where we're doing the majority of our work for the large and mid-cap ENPs, some integrated and some of the hybrid utilities. At this point, the private side combined with small publics is right around 40% of our total revenue. 60% is going to be -- 60% plus is going to be with the big players, frankly.

Okay, and then my follow-up would be you guys have always done a good job on being aggressive on your -- with the internal things that you can control. That came through again here in this quarter with respect to your frac margin. So what are you planning on doing in the back half of the year? What things you're implementing, have you already implemented? And whatever you've implemented in the second quarter, was that to the second quarter and what impact will that have as you get into the third and fourth quarter? Thanks.

Kurt, thanks for the compliment. I think about trying to control the things we control, as a management team, we're constantly looking at our businesses and trying to say, what level of equipment and personnel is appropriate, given the amount of business that we're doing. And we're always trying to keep the sizing correct, so going forward, we did that, obviously, in the second quarter. We're continuing to do that in the third quarter. But quite frankly, we think it's just part of our overall blocking and tackling that we see as part of our job. And I think we're, I'm pleased that you see us as doing a good job doing it. It's something obviously which we work at on a daily basis to try to achieve and hope we do it well. Doug?

Your next question comes from the line of Joe Hill representing Tudor, Pickering. Please proceed.

Of the $300 sequential day rate hit, how much of that is due to the mix effect of the stand-by rates?

It's approximately half of it.

And then what are your all's current thoughts on your 2013 capital budget at this point?

Well Joe, obviously, we haven't really even been thinking a great deal about 2013 capital, but I will say this. We've built 20 to 25 new-build rigs a year for the last three or four years. We're certainly -- we'll look at the market conditions, but we certainly would start out at least thinking in that direction. But obviously it's going to be based on customer demand. What we see, I think it should be obvious, that I don't really see a huge need for additional pressure pumping equipment. We have cold stacks, some new equipment that we've taken delivery of. I think that certainly will meet the needs we would have. I hope that changes, and we are ordering more equipment. But at the present time, I think I'd probably have to say that we don't really anticipate huge capital needs there. But I really can't give you a number today. I hope that adds a little color to what we're thinking, but we look at these things on a quarter-by-quarter basis, and we really won't make that decision until later in the year.

Okay, Doug. If I were going to tell you that say you were probably only going to get 5% to 10% of a 25 Apex new-build program contracted, would that influence your capital budget down, or would you be okay with that?

I think, Joe, that you're only talking about some of the factors. When you said that we would only get 5% contracted, my immediate reaction is, well tell me what the day rate is for both the 5% and the 95%. Because that to me, what you're expected day rate is over a reasonable course is what, in effect, should I think determine what you think the economics and payback are for this capital investment. And one of the things that we believe is that we're going to be successful with respect to the rigs that we're building in getting effective and acceptable day rates, which will in effect give us the right kinds of returns. If we didn't think that, we wouldn't want to complete the rigs.

Okay, thanks, Mark. And then finally from me, could you guys compare and contrast what you're seeing in Appalachia, the Marcellus versus say Texas, in terms of frac demand and customer behavior?

Let me start talking about the northeast. I think we started to see the -- because it's primarily a dry gas market, I think we saw some of the pressure on in both from the competitive environment and certainly pricing, we saw it earlier in the year. There was no question in that market there has been excess capacity. We believe some of that capacity has moved out of that market, but there's still probably more capacity than what we see as a current demand. Although we are encouraged by gas prices creeping up again, we are having customers that are starting to think again about getting back to work up there.

I think the big shift this last quarter has been primarily the flood of equipment and crews and people that have come in to the oily markets. Obviously, in our case that's Texas. I think both the Eagle Ford today and the Permian have seen an inundation of competitors. It's become incredibly price competitive in those marketplaces. But you know, we're a long established player in both of those markets. And again, as Mark said before, I think our service quality and the fact that we stick to our knitting and execute properly allows us to win jobs that maybe some of the new entrants have not proven yet.

Your next question comes from the line of Robin Shoemaker representing Citigroup. Please proceed.

I wanted to ask about we've seen a few drilling contractors report buyouts of term contracts. You indicated that you've got some rigs that are on stand by, but sounds like you haven't really negotiated any buyouts of term contracts.

Yes, Robin, I think that's fair to say. We've certainly had some customers ask us about the term contracts. But today, they're living to the terms of those contracts by continuous to having put us on stand-by rates as opposed to really a lump sum buyout, which I think is significant. And that they, it probably tells you that they think it's a short-term issue. And a lump sum buyout usually means that they've thrown up their hands and given up hope that they're going to put the rig back to work. In our case with the rigs going on stand by, we hope these rigs are actually go back to full operations before the term contract is expired.

Yes, I see the difference there. So in terms of the Apex rigs that I believe you have 17 coming out still to be delivered that have contracts out to 24. So on the other, on the ones that don't have contracts, I guess you will bring those out into a spot market. And how would you describe the spot market for these high-efficiency Apex rigs?

Firstly, we think the spot markets very, very strong for these rigs, and the demand for these rigs is still quite strong. The thing that's perhaps changed is the willingness of customers to sign three-year term contracts. Now, we have not made a decision as to whether we will put them out in the spot market if we don't have contracts. We're going to see how the market develops firstly. We haven't committed that and don't intend to commit that by this call. If in fact there are no contracts available, and if in fact the spot market prices are acceptable, then we may put the rigs out to those prices. But if the spot market prices weren't good, we wouldn't put the rigs out into those prices, and in fact would sack them. Having said all that, we are pretty confident, in fact quite confident that those rigs will go out under acceptable financial arrangements, and ones which we think meet our capital requirements.

I'll also point out that many of the rigs still to be delivered this year are much later in the year, including Q4. The last two or three quarters even in a somewhat market that's been difficult to sign term contracts, we still have been able to sign two or three a quarter. We do expect to sign additional contracts before the end of the year and before these rigs actually go out to the market.

Right, and so on Apex rigs whose contracts come up or are facing expiration or renewal, are you typically signing a new term contractor or are those mostly going on to a spot basis?

We've had about 50% of them on average that get rolled over by the same customer. Those that have been released, we've been very, very successful at placing them, in some cases, at better rates than we had under the term contract. But I will admit we are starting to see some of those Apex rigs that are coming free that we are having to put in the spot market. But typically those are some Apex rigs that have worked three or four years under a long-term contract, and quite often, would go on to a little bit shorter a contract when they roll over. It's not necessarily a bad thing, as certainly, I'm not sure we want to be signing long-term contracts at lower prices.

Yes, right, understood. Okay, thank you very much.

Just one clarifying comment, I may have misunderstood Robin's comments, but to be clear on our new build program, we plan to complete 24 rigs this year, and then we have the six that we deferred to early 2013. Of those 24 rigs for 2012, nine of them have been completed. Of the 24, 17 have contracts at this point, so the uncontracted rigs at this point for 2012 is [done]. And Robin, I may have misunderstood your comments. I just wanted to make sure we're clear on where we stand.

Your next question comes from the line of Marshall Adkins representing Raymond James. Please proceed.

A couple for me. First, on the stock repurchase program, would you clarify is the $150 million in addition to the $70 million you've already done? Or is that $150 million minus the $70 million you've already done?

It's $150 million of new, fresh authorization.

Okay, and am I to read into that, Mark, that your thought, at least in the last quarter, is that the best acquisition out there is our own rigs, in effect?

Well, Marshall, we thought that we were building new rigs during the quarter, so we were building rigs as well as acquiring our own stock. Quite frankly, we have the balance sheet that supports us and allows us to buy back our stock and keep still with a very, very strong balance sheet and with very limited leverage. And so that's the perception from our perspective is that we can afford to do it. When market conditions are appropriate, we're going to certainly take advantage of them. And at the same time, we're not ruling out the possibility of growth through acquisition.

Okay, perfect. Last one for me, pressure pumping, you blew the doors off there. You mentioned part of the reason you did so well was your supply chain. When others are get swallowed up by this floor issue, you guys didn't seem to be affected anywhere near the degree of the others. Give me a little more color on exactly why you all did so much better than the rest. Was part of it regional? And going forward, can we look for span costs or other cost issues we should be aware of in the next few quarters?

Marshall, I can't say that we've actually looked at our own results and performance necessarily against our competitors. We've certainly heard a lot of the noise from the competitors. We've looked at our own situation vis-a-vis our own customer base. And in particular, in the northeast, we had a rather lumpy Q1. And a lot of that was really because of some customer mix issues and some customer activity that we looked at things and said, is this going to continue? Will this get better?

One of the things about these big frac crews, its become increasingly important, you have such a small number of customers, that it's incredibly important to know exactly what those customers are going to be doing for the next 90 days. Now having said that, we saw the lumpiness in Q1 in the northeast and tried to react appropriately with our cost containment measures. But obviously again, you've got to work with your customers; you've got to have your supply chain in place. And quite honestly, I think our proven performance in both of these markets has allowed us to capture some work that maybe others didn't. Now, we also didn't move a bunch of equipment around. And every time you move equipment from region to region, you lose time and the ability to earn revenue. We had very little of that, so I think it allowed us to improve our utilization, particularly in the northeast.

Now, the southwest is a much different story. Again, we're very well entrenched. I think we're very well known. We do a good job out there, but there's no question, we've had this huge influx of competitors that have placed a great deal of pressure on pricing levels in particular.

Marshall, I just want to clarify the answer I gave to the authorization. The authorization, the total authorization currently in place is $150 million, as of today. So that's where we are as of today.

Okay.

Marshall, let me just finish that. On that, I think we're known for execution and the quality of our service, and I think that's what's allowed us to maybe post better results than our competitors. But again, we worry about running our own business and blocking and tackling, and not worried about so much about whether our competitors are either doing or not doing except from the point of view of how it impacts us.

And going forward, obviously we know there's going to be pricing issue for everyone out there. But should we expect somewhat of a cost tail wind benefit, if you will, from lower guar cost, lower sand cost over the next six to 12 months do you think?

Well, in our case, I think as I mentioned, guar is a very small part of our total cost of sales. It's probably less than 10% on average of our cost of sales. We have adequate inventories. I don't think we're going to see big swings in costs one way or the other. I think all of our competitors, including us, we've made commitments on sand purchases. Most of those commitments probably last somewhere between six months and 12 months. In our case, I really don't see any big swings in costs either up or down.

Your next question comes from the line of Waqar Syed of Goldman Sachs. Please proceed.

Hi, my questions have all been answered, thank you very much.

Your next question comes from the line of John Daniel representing Simmons & Company. Please proceed.

On the pressure pumping, is any of the margin improvements that you had in Q2, is any of it tied to lower R&M expense?

John, there's a little bit of a tie to supply costs and primarily with iron. Repair and supply really hasn't changed dramatically. There were some reductions in supply costs, which in our case, is primarily iron.

Okay, and just seeing if there's any deferral of maintenance in the quarter.

No, not at all.

The drop off in margins, I'm sorry, the drop off in margins for Q3 and pressure pumping, is that entirely price driven or are you expecting some costs to come back? If you answer that I apologize, I missed it.

It's mostly price driven and our best guess as to activity. One of the things, as you know, that hurts you in the pressure pumping business is continuous activity. And when you don't get that continuous activity, you're faced with how do you control your cost in that down period. So we're expecting primarily more price competition in both markets. We're expecting a little bit of lumpiness in the business, which causes some of those costs to go up.

Okay. Last one for me. We hear stories from some of the frac assemblers that a few of the private frac companies are having payment issues, some more so than others. If we assume that those problems persist and that could potentially create greater M&A opportunities, at this point what makes more sense to you, to continue the buyback plan? Or if you could hypothetically look at a competitor and buy them at say something close to replacement value, what would be your preference?

John, I don't want to set the pricing and really try to do that. I think you articulate the right question, although I would have said it more broadly, which is, would you prefer to buy equipment that you think is important and useful at a discounted price or to buy your own Company stock, which you also think is discounted? In my mind, the question turns on which you think provides the better long-term value for our shareholders. And quite frankly, that's a conversation that this management team has regularly and tries to assess it. And I'd love to be able to give you a simple answer to the question you asked, because frankly, it would save me a lot of sleep to be able to just know the answer was clear. But it's ultimately a judgment call that you make based on what the quality of the assets are that you can acquire, what your own stock price is, what your own prospects are, and a host of other questions, all of which are wrapped up together.

Okay, fair enough. Just one more then. You mentioned in the release, this is really minor, but the auction sale of excess drilling assets. Can you just elaborate on what you sold and perhaps where those assets went?

John, there was some assets that were acquired several years ago in the four corners area. The equipment, frankly, we've made our money back on it very quickly back when we bought it. That market has not been a good market for many of the years since then. We felt we could sell those assets to some of which went out of the country without them coming back to compete against us.

Your next question comes from the line of Dave Wilson representing Howard Weil. Please proceed.

Just real quick follow-up on the share repurchase, a little more on that. Mark, besides the comments you've already made regarding the repurchases, was it also a function of having an additional proceeds of $27 million from asset sales available to use it? Would such a lack of proceeds in the future change how you think about share repurchases?

It's interesting, you've put together two ideas, and I want to separate them. One is sure, having the $70 million approximate of proceeds, remember the price was about $42 million plus there was the auction proceeds plus some other total cash, bringing us up to approximately $70 million. Sure, having that incremental $70 million, and quite frankly, it came about and we did unexpectedly better than we had hoped for in some of those transactions. So that obviously was a positive impetus to rethink and consider and go forward with the stock buyback at the present moment. The truth is, however, that we have the balance sheet that would support us to buyback stock without that in the future. So while it positively impacted us towards doing it, the lack of it in the future wouldn't stop us from going forward. So I hope that's in answer to your question.

Your next question comes from the line of Brian Uhlmer representing Global Hunter. Please proceed.

I thought Andy was going to say the out performance was because of his role as COO, but I like his humility. But I have a totally unrelated question to that comment. When we're talking about pressure pumping, and your margins are double some of your peers, and you've got equipment sitting on the sidelines, is it a utilization game while you can't bring some of that equipment back and still make margins that provide nice returns for that equipment? Is it the fact that you can't hit utilization, or is it you don't want to affect pricing on all your equipment that's currently outstanding? How do you look at the balance between that?

Before they give the answer from the business side, I'd just like to point out when you look at margins pressure pumpers, I think we all consider things differently in terms of what's operating, what's G&A. So I think it's more looking at the relative change in those percentages. I don't know that our -- we are 50% more double our competitors, we may just align our costs differently across our income statement. Having said that, Doug?

Brian, I don't know that I could give you an answer. I guess both Andy and I would like to take credit for the fact, and with our operating groups that were just better, but the reality is, I think we are pretty well entrenched in two very different markets. I do think that it is a combination of utilization, but like a lot of things in this business, it's all about performance and people. And we have some outstanding people in both of those operations. I think we're very well known. We're not always the low bid. We're not always the high bid. But I think people really today do pay for performance and pay for getting the job done in a safe and efficient manner. And I think our guys in both markets have done an outstanding job of getting everything they can, given the market conditions. Now we hope it's always going to be better but as I said, we're not a newcomer to this business. We've been in the business a long time, and both with the ups and downs, we do know how to react and respond and try and work profitably.

So the probability of bringing back stacked equipment in the next couple of quarters would probably be close to nil, is that what I'm hearing?

We don't really see it unless we see a customer opportunity that we think is a little bit more than a short-term opportunity and we can continue to keep our service quality. I certainly hope that equipment will go back to work, but we're not in any rush just to put it in the marketplace to drive pricing down even further.

Okay, and a quick follow-up on John's question about making acquisition. He asked if you were willing to do something replacement value, and in your response, you said maybe at a discount to replacement value. I just wanted to clarify that you would not entertain something just at wherever placement value costs are right now, would you?

No, I don't think it makes any sense to speak about what price you'll pay. I wasn't trying, and I'm glad you asked the question so that I can clarify, I wasn't trying to be excessively cute and clever between book value and replacement cost and discount value. What I was really trying to say is that I think we have historically seen part of ourselves as being value investors. And so that when we're looking at an acquisition, we want to think that we're getting good assets at a very good price. And that's really what I was trying to highlight, not so much book, under book, discount to book or any of those things.

Your next question comes from the line of Jim Crandall representing Dahlman Rose. Please proceed.

I have a question for Andy, but Mark, feel free to jump in too if you want to. Andy, you come from a Company that strives to differentiate itself technologically if possible in every business that it's in. Certainly it had tried to do that in pressure pumping with debatable success, but I'm referring specifically to the highway project. Do you feel that this is a business where you can differentiate yourself more technologically speaking in the business? And if so, in what way?

Jim, good morning. So let me just speak in a broader sense of what I've seen in the three months that I've been here. It's been great for me to get out to the field and meet with the people and see the operations that we have. On the technology front on drilling side, the Apex 1500s are doing an outstanding job in the field. Their new AC drives with some interesting, and let me just describe it as interesting customization on traditional drilling technology that provides a package that our people can operate very efficiently. And we're seeing very good drilling performance in the field with those rigs.

On the pressure pumping side, some of the technology that we have has been customized from the companies that we have -- do the procurement from to meet our specific needs in the places that we work. And again, because of the customization there, I see that our people are doing a great job in being very efficient and very safe in the pressure pumping operations that we're doing. So while at Patterson-UTI and Universal Well Services, we're not getting specific customization with fluid chemistry. With the hardware and the equipment that we're using at the well site, certainly there's some unique things that we have there that are benefiting the customers right now.

And do you think specifically in pressure pumping that because of the technological advancements, whether they be in fluid chemistry or realtime monitoring or more significant things, that those can over a period of time, limit the volatility in pricing in the industry? It seems that every company likes to talk about technology, but we see some tremendous swings in pricing in this business that almost are unparalleled in any business in the oil field.

Yes, certainly with pressure pumping we have the supply/demand equation that continues to contribute to the pricing challenges. And as we've noted, we're still in a challenging market and working our way through it. I think it's a combination of things. We've got some unique bits of technology out there, but it's what allows our people to execute at the well site at the end of the day that makes a difference.

Okay, and I may have missed this comment, but in your pressure pumping business in general, roughly what percent of your business might still be on term contracts versus being on short-term spot work?

Jim, this is Doug. We've still got approximately 155,000 horsepower under term contract. And roughly, just rough numbers. I guess there's about 450,000 fracturing horsepower today that is not.

And the amount that's under term contract, Doug, are those really firm contracts? What pressure are you getting from the customers to reduce prices, and are you open to conversation that might extend duration and lower price?

Well, Jim, as I said, first off I'll say that the contracts that we've signed, I don't think there's been any question, people questioning whether they're legitimate contracts. They are valid contracts. Do we get questions from customers given commodity prices to see if there's any way we can come up with something that works better for them and works better for us? We do entertain those things, but its always got to be a win-win and it's a hypothetical question. But certainly would we entertain an extension of a contract for some other change in the contract? I would say we obviously have to look at the details, but we've certainly done that on the drilling side, but the validity of the contract is still the one thing that people have all recognized that yes these are valid contracts.

And then final question, may be one more for Mark. Mark, do you see in the future, maybe you can address both of the two businesses, do you see Patterson, let's just say over the next three to five years, becoming a, for lack of better word, national competitor with representation in all of the major basins in both the rig business and pressure pumping?

Jim, frankly one of the things we're conscience of is a management is that every time we think about our business and thinking about expanding it, and we spend time thinking about that in every management meeting including the one we've been in this week, we want to make sure that as we think about expansion, we think about profitable expansion. We've seen a lot of companies, in effect, get bigger, but in effect, not generate incremental profit. So for our perspective, yes, we would like to be bigger, but only if it means we're going to be more profitable as an overall entity. And that's really the question, so we'll expand into other regions if we think that there will be increased profitability in the aggregate. That simple.

I didn't necessarily mean bigger. I just, for example, if all of the rigs or pressure pumping equipment you had in the Appalachian and Marcellus region, if you had for example, half of that was in the Bakken and half there, and you had a more geographically spread out business, and I'm not saying your strategy has been bad. In fact, it's been good being concentrated. But I just wondered to what extent you view it as a strategic advantage that you'd be in more basins than you are now.

We certainly understand the logic of the question, which is that oftentimes, that you can lessen your risk and increase your returns by having a more diverse portfolio. And so having -- in fact on the rig side, have a very broad coverage spectrum. As you know, in the pressure pumping business, until a couple years ago, we were only in the Northeast. The acquisition that we did a couple years ago gave us the southwest. We're obviously considering the possibilities of expansion geographically, and always have been. But you are looking -- trying to pick your spots and pick the moments where you think you're having the best chance to succeed and do so at the best price, so yes.

Your next question comes from the line of John Keller representing Stephens. Please proceed.

Most of my questions have been answered, but I was curious if you could help us understand the location of some of those stand-by rigs.

I think there's no one sitting around the table who has a piece of paper, John, that gives us that information. So I think we're, we just don't know frankly sitting here.

Fair enough, and maybe more broadly thinking about the different rig classes, be it sub-1000 horsepower mechanical rigs or the AC electric rigs, et cetera, any of those particular asset classes that you're seeing weakness in or that you see as a greater risk as we look out over the back half of the year. Seems to me when I look through your fleet, that the lower-end mechanical rigs, particularly out in West Texas maintained pretty darn good utilization.

That's the way we see it at this point. We see all of our rigs equally performing, so we don't see any real sense of class differentiation.

So that's not more evidence saying the 1,000 horsepower mechanical type market is than anywhere else?

I think we all agree with that. We really haven't seen no real discernible trends you could say one or the other there's weakness.

At this time we have no further questions. I'd now like to turn it back over to management for closing remarks.

Thank you, Operator, and thank you, everybody for your participation in today's call. We look forward to speaking with you at the end of our third quarter, thank you.

Thank you very much. This concludes today's conference. Thank you for your participation. You may now disconnect. Have a great day.