Patterson-UTI Energy, Inc. (PTEN) Q2 2013 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Quarter 2 2013 Patterson-UTI Energy Inc. Earnings Conference Call. My name is Angela, and I'll be your operator for today. [Operator Instructions] As a reminder, this call is being recorded for replay purposes. I would now like to hand the call over to Mike Drickamer, Director, Investor Relations. Please proceed, sir.

Thank you, Angela. Good morning, and on behalf of Patterson-UTI Energy, I'd like to welcome you to today's conference call to discuss the results of the 3 and 6 months ended June 30, 2013. Participating in the call today 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 this conference call that state the company's or management's plans, intentions, beliefs, expectations or predictions for the future are forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995, the Securities Act of 1933 and the Securities Exchange Act of 1934. These forward-looking statements are subject to risks and uncertainties, as disclosed in the company's annual report on Form 10-K and other filings with the SEC. These risks and uncertainties could cause the company's actual results to differ materially from those suggested in such forward-looking statements or what the company expects. The company undertakes no obligation to publicly update or revise any forward-looking statement. The company's SEC filings may be obtained by contacting the company or the SEC and are available through the company's website and through the SEC's EDGAR system. 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 2013. We are pleased that you are able to join us today. As is customary, I will start by briefly reviewing the financial results for the quarter ended June 30, 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 second quarter. As set forth in our earnings press release issued this morning, we reported net income of $40.8 million or $0.28 per share for the second quarter ended June 30, 2013, and $97 million or $0.66 per share, for the 6 months ended June 30. Consolidated revenues for the second quarter were $659 million and EBITDA was $208 million. Our balance sheet continues to be strong as we exited the second quarter with $149 million of cash and equivalents and a very manageable 16.7% net debt-to-cap ratio. Second quarter results were below our expectations, due primarily to an increase in rig operating costs. The second quarter did not unfold as we expected, but there were a number of bright spots in both pressure pumping and contract drilling on which we continue to build. First, demand for APEX rigs remains high, as evidenced by our very high level of utilization for APEX rigs. More importantly, based on customer interest, we believe that the demand for APEX rigs will remain strong. We have seen a notable increase in contracting activity over recent weeks and have contracted our remaining new APEX rigs for this year. We believe the strong demand for both our APEX rigs and pressure pumping services is clear evidence of the bifurcation in both of these markets. There has been a secular shift towards high-spec drilling rigs and execution-focused pressure pumping companies, driven by the increasing complexity of wells and a greater focus on efficiency. This shift validates the decision we made years ago to invest heavily in a new fleet of APEX rigs and more than double the size of our pressure pumping business. The investment we made has paid off with high levels of APEX rig utilization, profitable returns, greater visibility to our earnings through term contracts and a more diverse customer base, including multinational oil companies and large independents. In addition to the benefits we have seen on the contract drilling side, the secular shift also positively impacts our pressure pumping business. It seems a simple fact, but it is often overlooked that when more wells are drilled, the market demand for pressure pumping services is greater. Despite challenging market conditions, our pressure pumping business has performed very well and stands poised to benefit as that market comes back into balance. With that, I will know turn the call over to Andy.

Thanks, Mark. In following our typical format, I'm going to start this morning with some commentary on our drilling business and then finish with some comments on our pressure pumping business. In contract drilling, with the continued growth of our APEX rig fleet, we experienced a record level of activity for APEX rigs, which was offset by lower conventional rig utilization and the seasonal slowdown in Canadian drilling activity. We are pleased that during a period of flat industry rig counts, our APEX rig utilization at 96% led the U.S. high-spec rig utilization. In the United States, we averaged 183 operating rigs during the second quarter, compared to 188 during the first quarter. With the seasonal breakup in Canada, the Canadian average rig count was 2, which was down from 11 in the first quarter. Greater APEX activity, along with lower conventional activity, increased the proportion of higher day rate APEX rigs in our fleet mix. Accordingly, average daily revenue in the U.S. increased during the second quarter to $22,990, despite $120 of greater benefit in the first quarter from lump sum early termination revenues. Our total average revenue per day, including Canada, of $23,120, decreased sequentially due to the seasonal slowdown in Canada. Total average margin per day of $8,730 decreased sequentially due to an increase in rig operating costs, a decrease in lump sum early termination revenues and the seasonal slowdown in Canada. The increase in rig operating costs equated to an increase in average operating costs per day of $590, up to $14,390 and was predominantly caused by 2 factors: first, a rig utilization schedule that included rigs moving between regions and some rigs stacking, while others were being activated. Second, the continued improvement of our preventative maintenance process, which had some associated costs. This should ultimately lower repair costs on a long-term basis and has already resulted in increased uptime, which improves revenue. We expect these costs to decrease to more normal levels as the year progresses. During the second half of the year, we expect to recognize early termination revenues totaling approximately $60 million related to the early termination of the term contracts for 6 rigs. I'm very pleased that with the strong demand for APEX rigs we are seeing in the market today, we were quickly able to contract these rigs with other customers and therefore, the impact to our utilization from the early termination should be negligible. We expect all of this early termination revenue will be recognized during the third quarter, but the timing of the rig releases is dynamic and some could potentially slip into the fourth quarter, thereby delaying the recognition of a portion of the expected early termination revenue. In the third quarter, we expect our rig count in the U.S. to average 183. In Canada, activity is recovering following the spring breakup, and we expect our third quarter Canadian rig count will average 8 rigs. Excluding early termination revenues, we expect total average revenues per day of $22,700 during the third quarter. The sequential decrease of approximately $400 per day is related to contract rollovers, including the 6 early terminated rigs, partially offset by the increased activity in Canada. Total average operating costs per day are expected to be approximately $14,250 during the third quarter, a decrease of approximately $150. Turning to our APEX rig newbuild program, we delivered 3 new APEX-XK 1500s during the second quarter, of which 2 had walking systems for pad drilling. Additionally, we upgraded 1 existing APEX rig with a walking system. This brought our total APEX rig fleet at June 30 to 120 APEX rigs, of which 68 had walking capabilities. We have now contracted all 13 new APEX rigs that are included in our 2013 budget. Of the 6 new APEX rigs still to be delivered, all 6 have been contracted with walking systems. Additionally, we recently received a request to add a walking system to the one new APEX rig that was originally delivered without a walking system in the second quarter. Accordingly, all 13 of the new APEX rigs in our 2013 budget will have walking systems. We also continue to see demand from our customers for rigs that use natural gas as a fuel source. We currently have 4 rigs operating with 100% natural gas engines, with an additional 5 rigs slated for future natural gas upgrades. As well, we currently have 17 rigs with bi-fuel systems installed, with 2 rigs slated for bi-fuel upgrades. We are also in discussions with customers for additional bi-fuel systems. So by the end of 2013, we expect to have approximately 30 rigs utilizing natural gas as the primary fuel. Our reduced newbuild construction program in 2013 allowed us the opportunity to take a step back and review some of our procedures in supply chain. The purpose here was to try to increase efficiencies and squeeze some other costs out of our newbuild construction program. Through several initiatives that have advanced our rig manufacturing process, we have been able to reduce our capital cost per rig by approximately 10% since the end of last year. With all these stages, we now expect to deliver 1 new APEX rig in the third quarter and the remaining 5 new APEX rigs in our 2013 budget during the fourth quarter. In 2014, we expect to deliver approximately 12 new APEX rigs through the first half of the year. During the second quarter, we signed 24 term contracts and as of June 30, our total term contract backlog exceeded $1 billion. Based on contracts currently in place, we expect to have an average of 121 rigs operating under term contracts during the third quarter and an average of 113 rigs operating under term contracts during the second half of 2013. Turning now to pressure pumping. The second quarter represented the third sequential quarter of revenue growth for pressure pumping, with revenues increasing 10% sequentially to $255 million. EBITDA from pressure pumping increased 6% sequentially to $62 million. This is a record level of pressure pumping revenue for us. Our revenues are now up 40% from the third quarter of 2012. This business has performed well due to our strong focus on well site execution, which has allowed us to keep all of our equipment working and also to previously activate new equipment. The full impact of which was realized in the second quarter. Additionally, we have benefited through incremental 24-hour work, which accounted for approximately 2/3 of our fracturing revenue in the second quarter. For the third quarter, we expect our pressure pumping revenues will remain relatively flat, as the market is still oversupplied. The gross margin is expected to be slightly lower at 24.5%, as there continues to be pricing pressure. With regards to pressure pumping technology. We continue to strengthen our competitive position in the industry. We believe that we are an industry leader in natural gas bi-fuel pressure pumping and that we have the largest bi-fuel frac fleet operating of the Marcellus. We have already completed more than 250 stages utilizing natural gas as a fuel source. And by early next year, we expect to have sufficient capacity to convert enough units to effectively quadruple our current bi-fuel fleet. As in drilling, we believe that natural gas bi-fuel is an important green technology that both reduces the environmental impact of our services and generates cost savings with our bi-fuel units able to cut diesel fuel consumption in half. Year-to-date, we have replaced over 40,000 gallons of diesel with lower cost and cleaner-burning natural gas and thereby, eliminated over 300,000 pounds of transportation loads on local roads. In the Southwest, we have recently opened a new facility Midland, Texas to support the increasing level of horizontal activity in the Permian. This new facility improves our maintenance efficiency and our products and chemical-handling capacity. Further to this, we have built a new larger laboratory for testing fracs, cement and acid service chemistry, which we believe is one of the most comprehensive and organized fluid testing facilities in the Permian Basin. 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. Our CapEx for 2013 is now expected to be approximately $800 million, as we order certain long-lead items for 2014, primarily for additional drilling rigs. SG&A during the third quarter is expected to be $18 million. Depreciation expense during the third quarter is expected to be $139 million. Our effective tax rate for the third quarter is expected to be approximately 36.5%. And with that, I will now turn the call back to Mark.

Andy, thanks. Before I pick up, I just want to make one small correction. During the second quarter, we signed 25 term contracts. I think we may have said 24. I just want to correct that for anybody who heard that and potentially misheard it or missed that when we spoke it. Andy, thank you. In the contract drilling, our outlook remains positive due to the strong demand for APEX rigs. More importantly, our confidence in this outlook has increased over the recent weeks due to the notable increase we've seen in contracting activity. We are delighted to have successfully contracted all of our budgeted new APEX rigs for 2013 and the 6 rigs that are being early terminated. I believe the high level of demand for APEX rigs and their industry-leading utilization level in the U.S. is a testament to the quality of our APEX rigs and our people, as well as a vote of confidence in our pad drilling technology. Our walking technology continues to offer customers the greatest amount of flexibility in planning their pad layout and growing demand for fast-moving, pad-capable rigs has benefited our contracting -- our contract drilling business. Similarly, our pressure pumping business has performed well despite challenging market conditions. We weathered the storm and were able to keep all of our crews working at acceptable margins. We believe we are well-positioned to benefit when this market comes back into balance. The bifurcation in the pressure pumping market is becoming more pronounced. I tend to agree with market research reports that it characterized this market as a market of haves and have-nots. More importantly, I believe our financial results and innovative technologies demonstrate that we are one of the haves. We achieved this position through our focus on well site execution. We will continue to have this strong focus, but we are not sitting back and resting on what we have done. We are continuing to innovate new ways to deliver value to our customers. With that, I'd like to thank our employees whose hard work and focus on customer satisfaction makes Patterson-UTI a company we can all be proud of. I'm also pleased to announce today that the company declared a quarterly cash dividend on its common stock of $0.05 per share to be paid on September 30, 2013, to holders of record as of September 16, 2013. Operator, we'd now like to open the call up to questions.

[Operator Instructions] The first question we have comes from Jim Wicklund from Credit Suisse.

This is Brittany Commins. Jim's at a funeral this morning. Sorry about that. So are there any trends you're seeing in pressure pumping? We've been hearing service companies talk about record frac stages. Is it something you're seeing, and are you still bidding per frac stage on new jobs?

So that's a good question. What we've seen in the trends that we have, in the Northeast and in Texas where our crews work is we've seen increasing amounts of 24-hour operations. So our revenue is a function of 24-hour operations did increase slightly. So we're up to about 2/3 right now. And so we see that continuing as intensity on pads continues to increase. But with regards to bidding per stage, we certainly don't do that. We have pricing contracts in place that we have an agreement with customers that ties up our frac crews with a particular customer for a period of time and therefore, we're not continuously bidding our frac crews either day-to-day or week-to-week or month-to-month.

All right, great. And can you maybe give a little more color on the bifurcation you were talking about? What makes the difference between the haves and have-nots?

What we've seen over the last 1.5 years, certainly in the market, has distinguished, I think, different companies in the pressure pumping business. And one of the things we were very proud of last year is when natural gas prices came down and certainly, the amount of work that was available in the U.S. came down, we were able to keep all of our crews working and we were able to them all working at reasonable margins in tough times. And so, as we came out of last year and into early this year, we were able to activate more horsepower and meet the demands of customers. So I think it clearly demonstrates that we provide excellent service quality at the well site that customers can count on and we have a lot of good teams and people in that business that are doing a great job.

The next question comes from James Rollyson from Raymond James. James M. Rollyson - Raymond James & Associates, Inc., Research Division: Andy or Mark, your rig count last quarter came in maybe a little bit under the overall Baker numbers. And it looks like kind of what has been driving that is conventional rigs may be falling off and you're holding up and adding to the APEX rig fleet. It sounds like, based on the guidance, you're down another couple rigs. I think you said you're delivering one new APEX rig. Just curious how you see that trend. Is that something you think continues, where some of the conventional rigs get kind of squeezed out of the market as long as the rig counts stays where -- roughly where it is now, number one. And then maybe just a little reminder of the margin differential between APEX rigs and conventional rigs so we can think about how this mix works for you going forward.

Yes, certainly, as we finished up Q1 and going into Q2, we expected the rig count to be a little bit higher than it was, especially given commodity prices. But I think what we saw are -- a lot of our operators and customers in West Texas, in Mid-Continent trying to evaluate exactly how they will want to work some of these plays, how they want to make shifts from vertical to horizontal. And we saw some of that shift take place. And I think we saw a little bit of a slowdown in some of the bigger independents that have -- the property certainly in the Permian Basin are just trying to evaluate and figure out what the horizontal development plans need to look like. So we certainly -- we felt that impact in the rig count in Q2. As far as what we're seeing -- we have a nice uptake of the new technology. We're sold out on the rigs for this year. We've had to go back to the board and talk about capital expenditures for the first half of 2014, and so we see continued uptake of new technology. There's no question that, that's happening. And I think it's really going to be the commodity prices that drive how the rest of our fleet continues to operate. And with regards to the margins, the APEX rigs have higher margin than what we gets on the others. As we continue to upgrade the fleet, we're going to continue to upgrade the margins of the business. Mark, you want to add to that?

Yes. Jim, I think, this is very much a part of a story that's been going on for quite a while with Patterson. We've spoken about the transformation of the company as we develop this new technology and this new advanced capabilities in these drilling rigs, and as I see it, what you're seeing in the marketplace now is just a continuation of what's been happening. Right this minute, I think the thing that we've seen, and it's the thing I think everybody in the industry has seen is that there was more optimism for a higher rig count this year, where the sort of thought was it was going to trend upward from the beginning of the year toward the end of -- until the end of the year. Obviously, we haven't seen that. And that's been the one sort of surprise of the year so far for, I think, everybody in the industry. One of the things that we're recognizing is that's going on. And in a flattish rig environment, this is what we're saying. James M. Rollyson - Raymond James & Associates, Inc., Research Division: That's helpful color and just as a follow-up, maybe -- when you say the 6 rigs that came off contract that you're getting paid out on and you've been -- congratulations in getting those back into the market fairly quickly, can you maybe just speak to how rates on re-contracting those rigs are running in maybe comparison to some of the newbuilds or the initial contract prices you had?

Those rigs were contracted in a period that was a little bit different. So as these rigs came off contract and been re-contracted, they have come down on the base rate of the rig by about $1,000 to $2,000 a day on average, depending on the customer. But when we look at the newbuilds, and there's certainly still some excitement around our newbuild technology, we're still in the mid-20s and up on newbuilds.

The next question comes from Ryan Fitzgibbon from Global Hunter Securities.

If I can expand on Jim's question there, the 25 new term contracts that you signed during the quarter, how many of those were for APEX rigs? And then, when we think of the margins that you're expecting out of those contracts, given the sequential decline, should we think of those as -- it's going to be $1,000 [ph] a day or are they better?

I think approximately 15 of those were new APEX contracts of the 25.

Approximately 15 were APEX and 5 were newbuilds.

15. Sorry.

Okay. And then any thoughts as to how we should think about margins for those 25 contracts as opposed to where you shook out in the first half of the year?

I think the margins on those contracts would vary depending on which -- different customer demands, different marketplaces they're going to. I think it'll be pretty hard -- Andy, maybe you're capable of giving...

[indiscernible] revenue...

Yes. We have to kind of speak around averages because every rig, we have a base rig that we build. But different customers come in and want different things, they go to different basins, they have winterization. And so that's why we say, newbuild rigs, we're signing these this up in the mid-20s and up, depending on the different extra services that a particular operator might require with the rig. But in general, back to the 25 new contracts that we signed, of which 5 were the newbuilds, they just kind of varied on the contracts, depending on when the previous contract may have been signed. But we're certainly pleased with the uptake on the newbuild technology and the rates that we're getting there.

Okay, that's helpful. And then, in terms of the sequential costs decline that you've talked about. Is it safe to assume that you're still moving rigs around the regions during the quarter? It doesn't look like you're stacking additional rigs, given the rig count guidance. I'm just trying to reconcile why costs won't be down a little bit more sequentially.

There's still going to be some movement as we go into Q3 with the rigs, maybe not as much as Q2, but we don't have full visibility on that yet. But in general, we're looking at getting some of the cost back in line. Like I mentioned in the comments, we have continued to improve our maintenance systems. And we are doing a little bit more preventive maintenance, and we did incur some additional costs in Q2 for that and we'll be working those costs back down through the rest of the year.

The next question comes from Byron Pope from Tudor, Pickering & Holt. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: I have a question on the pressure pumping side of the business. You guys have clearly demonstrated that you're among the haves, just in terms of the results for your pressure pumping business. And so, in thinking about an environment where you're -- you've already got roughly 2/3 of your spreads on 24-hour operations, it doesn't feel like there's much room to move that much higher. But I just wanted to kind of test that notion.

So as you said, we're working about 2/3 as a function of revenue, not the equipment. But as a function of revenue that we're generating, about 2/3 comes from 24-hour operations. But if we look at those 24-hour operations, they're not necessarily 7 days a week. So I wouldn't say that we've reached the end of what we can do in 24-hour operations. We have different customers that might use this 4 days a week or 5 days a week or 6 days for these 24-hour operations on the pads. Does that make sense? Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. It does. And really, where I was going with my question is thinking into, let's say, the first half of 2014, the fact that you've got decent utilization already, a decent mix of work already, your ability to potentially place incremental frac spreads with existing customers, I'm just trying to get some context for how you might think about, if and when, you might order some additional frac horsepower, just given your ability to kind of put it to work at decent economics.

We look at these kind of things all the time. We're certainly very proud of the activity levels that our teams in pressure pumping have been able to accomplish during a relatively tough environment. I'm not sure we're quite ready to place an order or anything like that. It's still a bit oversupplied and there's still a bit of pricing pressure out there. I think, as an industry, we need to work through some of the equipment that still sits on the sidelines, but we'll continue to keep an eye on that.

The next question comes from Waqar Syed from Wunderlich Securities, sorry, from Goldman Sachs.

My question relates to the operating cost. Is there any difference between the operating cost for the Tier 1 APEX AC rigs versus the smaller mechanical rigs?

Waqar, generally, there's not. Operating cost per day for a mechanical rig versus conventional electric or APEX are very similar. Where you can have some differences for any of the rig groups is if a customer requests additional services that have third-party cost or rental, things like that could impact the cost line. But if you look at the direct operating costs, they're very similar.

So -- but in general, when you look at -- like, based on all these third-party services, do you run them more from your -- on your Tier 1 rigs or on your lower rigs. And the reason I'm asking is that as your mix shifts towards more AC or Tier 1 rigs, does that also imply that operating costs go up or go down or it doesn't change?

Frankly, I think they're very similar. If I look at the last couple of quarters, they're within a few hundred dollars a day of each other and the actual difference, taking all of the rigs that we're running as a group was actually on the mob side, so it was a few hundred dollars on mobilization costs, but the direct costs were very similar.

Okay, great. And then on your pressure pumping fleet, I understand -- is that correct that 90,000 had all the [ph] horsepower rollover to spot rates some time in the fourth quarter?

Yes, that's about right. But I wouldn't say that necessarily rolled to spot rate. We have been very successful, on average, in keeping our pricing above spot levels.

Okay. So what would that do to the margins as we look into the fourth quarter? Any preliminary feel for that? Let's say the market does not change.

It's hard to say exactly what's going to happen in the fourth quarter yet. Pressure pumping could be impacted by some seasonality, but at the same time, 2/3 of the revenue comes from 24-hour operations on pads, so...

Next question comes from Jason Wangler from Wunderlich Securities.

I just had 2 more maybe on the early termination. One, could you maybe indicate how many customers let go of those rigs? And then also maybe if there was any read-through on the regions?

No, we don't address particular customers. We're just very pleased that these were high-quality rigs that were performing well and they were snapped up very quickly in the market.

Okay. Maybe if I asked one other way, just -- was it one customer that gave them up or were there multiple? That's the only thing I was curious about?

We can't speak to that.

The next question comes from John Daniel from Simmons & Company. John M. Daniel - Simmons & Company International, Research Division: Andy, I know it's hard to predict Q4 seasonality. But just hypothetically speaking, if activity levels stayed exactly the same as Q3 levels, given the repricing of the 90,000-horsepower, even if it is slightly above spot rates, I mean, should we expect margins to decline in that scenario?

Let me clarify that the 90,000-horsepower -- those contracts actually continue through Q4. It would be the end of Q4 that they would roll effecting Q1, but not Q4. But with regards to seasonality, I mean, it's just -- it's hard to predict. Like I said, it's nice to know that we're generating 2/3 of our revenue from 24-hour operations on pads, which means our crews can stay in place for longer periods. But we could get a big dump of snow in Pennsylvania, and that could change some of the dynamics, so... John M. Daniel - Simmons & Company International, Research Division: Absolutely, okay. Fair enough. One Canada thought -- your Canadian fleet size has been relatively steady over the years, just given all of the positive outlook for activity. Given LNG prospects, are there any plans to expand in that market?

We're very pleased with how our Canadian operations are running. And I think they're well-poised to -- for any future expansions in that market. We're always in continued discussion with the customers up there and we'll continue to keep an eye on things. John M. Daniel - Simmons & Company International, Research Division: Okay. Well, final one for me, just on the cash margin guidance. It looks -- it's coming down in Q3. Will contract rollovers or rig mix, as you think about Q4 again in an "all else being equal world," do you -- would cash margins be lower in Q4?

Historically, John, we haven't really spoken to fourth quarter. We've typically just spoken to the next quarter. And the reason for that is not that we're coy. It's because we've always felt that we didn't have very good visibility out more than a quarter. If there was ever time at which I felt that way, this might be the perfect moment. Frankly, with commodity prices, where they are, I find the activity level to be difficult to understand. And given that kind of bifurcation between the price of the commodity and the price -- and the level of activity, it's particularly hard to sort of speculate about what the fourth quarter will look like.

Next question comes from Robin Shoemaker from Citi.

My question was also about the second half of the year. But there's a lot of talk about now drilling efficiency and whether or not the E&P companies are overspending their budgets in the first part of the year. And without further upward adjustments to those budgets, they may be setting up for a repeat of last year's fourth quarter, where they cut back. Any -- do you have any thoughts on that, or would any of your customer inquiries about your future rigs that you have working for them indicate that we may see a curtailment towards the year end like we did last year?

Robin, the short answer to that question is no. We have not seen that from our customers. In fact, as I think we've tried to indicate in both our press release and in our prepared remarks this morning, we've seen a significant uptick in contracting activity. And this has been seeming to indicate to us that people have pretty strong feelings towards the end of this year, beginning of next year. So we don't see this indication of a falloff at the end of the year. But again, the caution I offered in the call -- in the -- to the question before from John Daniel is the same thing I'd offer to you, which is that it's very hard to get great vision here in this business from more than one quarter.

And I'll add that one of the things that I'm enjoying is that we have a very broad customer base for our drilling business. And if I look at a generalization across that large number of customers that we have, we're just not seeing that. And I think we're still relatively optimistic for the second half of the year.

If I can add one more thought, Robin, which is the following. In this quarter that just passed, in this period that's just passed through today's date, we managed to sell out all of our newbuilds for the rest of this year, plus replace those 6 rigs. That's been a pretty successful indication, in my mind of -- a pretty clear indication in my mind of the demand that we're seeing for our high-quality rigs.

Okay. So my other question is, since it's pretty clear now that the E&P customers get the value proposition of the APEX and AC drive rigs, so your demand there is growing pretty much at the expense of conventional rigs. So really, my question is about what you see as the long-term outlook for your conventional rigs. And I say that in the sense that sometimes, we see that with drilling contractors, when there is low utilization of particular asset class, there's an impairment test that's usually comes at some point. And that is -- that's really the reason for my question.

Yes, Robin, this is John. We look at the valuation of the rigs, all the rigs, particularly the mechanical conventionals, on a regular basis. And over the last 3 or 4 years, 3 of the 4 years, we've had some retirement of rigs. We'll look at that again this year. Whether there'll be an impact is unclear. But if you look at the last several years, it's typically been a pretty small number because the rigs we're talking about were bought many years ago and are very depreciated. But of course, we will continue to look at that with the passage of the time.

Yes. So just on the -- out -- the niche for conventional rigs today, how would you describe that?

We continue to generate cash flow from the conventional rigs. The funny thing that's kind of occurred the last few years is we have not seen a stronger natural gas price, which is where these rigs historically have made their greatest returns. So post-2008, the gas price has been quite a bit lower. And as a result, in the last few quarters, more than 70% of our revenue is coming from multinational majors, big independents and only 30% is coming from the private players who tend to focus, on average, more on these vertical wells that would put more of the mechanical rigs to work.

I realized your question was financial, but I'll talk a little about operational and technical. All the rigs that we have in the fleet today have worked since 2008. They're all capable of drilling wells. And when I look at industry numbers across the top 4 drillers around the U.S., I see that we still have the highest utilization, even in that SCR mechanical class. So we're still pleased with the level of activity that we're getting out of those rigs, even though it's a bit of a challenging time in the West Texas Permian Basin, as operators work through their plans on how they want to make shifts or how they want to redevelop some of those fields.

The next question comes from Constance Hsu from MorningStar.

I'm just wondering with the excess capacity in the pressure pumping market, and you guys have a very strong balance sheet. I'm just wondering if you guys are looking at any M&A potentially to perhaps acquire some of your smaller peers?

Constance, I'm not going to speak to any particular transaction. But we have historically always looked for opportunities and made it a kind of a business proposition that if there's an opportunity, we'd like to take a look at it. So if there are, we'll probably take a look at them, but I'm not going to speak anything in particular. Historically, we've been value buyers and we've always felt that if we were going to buy something, we had to be pretty confident that we were assured of a good return for our shareholders.

[Operator Instructions] We have further question from Jim Crandell from Cowen.

For your newbuild contracts, what is the average duration of your contracts for your '13 or so, I think, newbuild contracts, and are they skewed toward any particular basins?

So the first part of your question, where the majority of these new build contracts that we're signing today are in the 2- to 3-year term range. And like I stated earlier, pricings in the mid-20s and up. So we're very pleased with how that's progressing. But they're not skewed to any particular basin. I would say, they're relatively spread out around the U.S. markets right now.

Okay. And I know there was a question about Canada, but the companies who were much larger than you in Canada seem to be very optimistic about potential newbuilds and they're announcing newbuilds in Canada. Do you really believe you're a legit competitor to win some of the contracts who -- that for rigs that could be built to drill in the Horn River? And in anticipation of this LNG play that's developing up there?

While we're not one of the biggest players in Canada, we do provide a very good quality service up there and we have a good reputation, been in business for a while. And I think if some of those really do materialize, it'll certainly be the strength of our business in the U.S. market combined with the strength in the uptake of our APEX rigs in the market that could help potentially drive that.

Okay. And do you think you could be cost competitive for delivering a newbuild with the larger companies for that region?

I don't think we would have any issue with that. We have built rigs in Canada in the past. If we needed to do that, we could do that as well going forward.

Okay. And if you mentioned this, I'm sorry. But could you talk about day rate trends for the SCR rigs in the Eagle Ford and Permian on short-term contracts or spot contracts, what's happening there?

We haven't spoken about it previously. I'm not sure we have good information with us right here. John, do you have anything you want to add to that?

Yes, Jim. Sorry, but we do not get super specific about it, but it's reflected in the numbers we've talked about. There's some slippage in the pricing of spot rate rigs. But I wouldn't want to give any...

Yes. I'm not asking for numbers. I'm asking for overall trends in day rates for SCR rigs in those 2 basins where you're renewing on a spot basis.

I'd say maybe slightly down, but not significantly down. It's just a -- it's kind of an operator need that's happening over there, where you've got operators starting to experiment with horizontal wells, but you don't have full-blown developments yet, you don't have full plans in place.

Okay. And one final question. To get to this pressure pumping horsepower that's coming off-contract at the end of the year, is this your only horsepower that you would say is above market day rates?

No. I would say, Jim, that we think that -- that basically, we've been able to secure better than, in effect, the market rates, and I think that's reflected in the margins that we generate in pressure pumping, which I believe to be at least as good, if not among the leader in that business. So my response to that is no, I don't think we have taken just pure market. I think we've been rewarded for service quality levels that are higher. Frankly, I don't think a lot of companies in the pressure pumping business can say they've had 3 consecutive quarters of record revenues, which is well...

Good point. Mark, I'd really -- I guess, I misstated the question. Good point, though, to reemphasize that. But I guess my question is, besides that 90,000 horsepower, when it comes off, do you consider yourself, if market conditions remain about the same, are there any other -- is there any other horsepower [ph] that you think would be vulnerable to lower prices from where it is today?

Jim, it's is one of the things where we have been fighting a battle for now, in my mind, several years in which there's been an oversupply of equipment. And in this oversupplied market, the problem is, how do you keep your crews working, but how do you do so without, in effect, getting down to below an acceptable rate of return on the capital that you have already expended. We think we've been able to do that. And I really have to tip my hat to our operations people, both in the Northeast and the Southwest, because I think they have been able to do it by providing what the customers perceive to be a superior value proposition in terms of the quality of the work and the price that we charge. And the ability to do that and get above, in effect, the spot market, lowest price in the market, is really what's distinguished us. And frankly, we're really proud of that. I don't want to jump up and down about it because I don't think the war is over. There's still this oversupply of equipment that Andy has spoken about before and we're still fighting the battle, but we're doing a pretty good job so far.

And I think it's really -- I was just going to add to that I think it's a bit too early to say exactly how it's going to play out. I mean, if you look at what we've all talked about in the industry, we continue to see rig efficiency approved and the well counts are -- continue to climb. And our pressure pumping business, the pressure pumping business, in general, is one of the beneficiaries of improved drilling efficiencies. So as we work through the rest of the year with increasing well counts, I think it's just going to -- we'll have to say how it plays out and how much equipment comes off the sidelines towards the end of the year.

Okay. And then one final thing is, there was an announcement that Baker Hughes, in pressure pumping, disclosed the receipt of a civil investigative demand from the DOJ related to prices in pressure pumping, and I'm wondering if this is an industry type thing or related specifically to Baker Hughes. Did you receive any information for a DOJ investigation, or is this solely -- or do you know nothing about it?

I'm aware of what the filing that Baker made. We wouldn't comment on any investigation. But obviously, if we had to -- something that we need to disclose, we would.

Next question comes from Brad Handler from Jefferies.

I want to apologize up front. I was not able to listen to much of your call. And if this is a redundant question, forgive me, but I'm going to swing a little wider and hopefully, it won't be so much. I was -- I'm trying to think a little bit harder about using conventional rigs, mechanical rigs, to drill top-hole sections. And I'm just sort of wondering, how much of that -- how relevant is this phenomenon, in the sense, in your business? And perhaps, you can talk about it. I think it's more relevant in the Marcellus and the Utica, for example, relative to some other parts. But if you can talk about that, that would be great. And then sort of a related question is, is there contract -- is there any contract kind of comfort when you can tie in a mechanical rig to drill top-hole sections in with your own, perhaps it's an AC rig, to do the horizontal sections. And if so, is there some comfort that have in the portion of your business that stems from that phenomenon?

So I mean, it is true that there are rigs out there that are really specific and small and drill top-hole sections sometimes with air packages up in the Marcellus, and we even see it occasionally down in the Eagle Ford as well. But in general, these are smaller rigs than what we carry in the fleet. These are small-truck matter rigs that are just a lower horsepower than what we have. And we follow these rigs all the time in various basins, but it's -- it doesn't really impact us.

Our sense would be that, that's low-margin work also.

Yes. I'll just add that if you look at a lot of the industry data out there that's counting wells, I think sometimes, there's some confusion in the data because you've got one rig that comes in and drills a surface hole and later, you have one of our big APEX comes on to drill the rest of the well. And so sometimes, these wells get double counted in some of the data that's out there.

That's interesting. So as we look at some of the Marcellus well data presumably, most of all, it might be subject to overstatement.

Overstatement. And also, when people are trying to aggregate data and numbers to try to calculate what drilling efficiency is occurring during the year, sometimes things get double counted.

I'd now like to hand the call back to Mark Siegel for closing remarks.

I'd like to thank everyone for joining us on our July call, reporting our second quarter earnings. We look forward to speaking with you again in October as we report third quarter. Thanks, everyone, for joining us. And with that, I'll say goodbye.

Thank you. Ladies and gentlemen, that concludes your conference call for today. You may now disconnect. Thank you for joining, and have a good day.