Good day, ladies and gentlemen. Welcome to the Q2 2012 Patterson-UTI Energy Inc. Earnings Conference Call. My name is Sheverly and I'll be your operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like turn the conference over to your host for today, Mr. Mike Drickamer, Director of Investor Relations. Please proceed, sir.

Thank you, Sheverly. Good morning, and on behalf of Patterson-UTI Energy, I'd like to welcome you to today's conference call to discuss the results for the 3 and 6 months ended June 30, 2012. Participating in the call today will be Mark Siegel, Chairman; Doug Wall, President and Chief Executive Officer; Andy Hendricks, 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 rate, 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 material; 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 statements. 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 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 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 6 months ended June 30. EBITDA for the quarter was $279 million. The financial results for the second quarter include a pretax 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 U.S. rigs operating and average margin per operating day were near our expectations, which was a significant accomplishment as rigs moved 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 climbed by 15%, which was actually a lesser decline than we had expected, and EBITDA declined by only 10%, helped by cost controls which we have implemented. These accomplishments in operations were mirrored in 3 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 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.

Thanks, 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 U.S., 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 U.S., our activity levels remained strong and although we have seen some softness in certain markets throughout the quarter. At the end of the second quarter, we have 6 rigs under term contract that were on standby rate. For lack of a better word, I'm going to characterize the U.S. 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 contracts. 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 5 rigs working in this market. While one might expect that the changes in the U.S. market would have had a negative impact on day rates, during the second quarter, our average revenue per operating day in the U.S. increased by $270 to $22,480. While pricing and dry gas markets is certainly more competitive, our ability to move to rigs to the oily markets and the impact of newbuilds has kept our pricing up.…

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 this field are highly skilled 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 with Patterson-UTI who are on the call today, I would like to thank you for the strong foundation that you've laid out with 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, Apex 1500 rigs with the latest control systems for maximizing drilling rigs, or an on-the-flight dry gel blending system for frac-ing operations that reduces dependency on liquid gels, our people has some of the newest and most advanced equipment in the field. This makes for a great combination of providing top service quality to our customers. And while I've known many of our customers for years, it's been nice to see where Patterson-UTI's many long-standing relationships with our customers. We work together through the ups and downs of the energy cycle, and with 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 their customers, employees and shareholders. I came to this company because of the great opportunity that we all have here, and after seeing the 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 increase in a day oil price volatility heightened price concerns. In turn, operators set an increasingly cautious outlook towards long-term capital commitments for oil projects as industry participants tie -- try to assess the complex array of factors determining oil prices. Faced with these changing market conditions, our drilling and pressure pumping operations both ha 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 noncore assets, the repurchase of more than 3% of our company's 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 strengthen 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 on 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 downward pricing pressure in the third quarter, we are encouraged that oil -- 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 the drilling and frac-ing programs. Finally, I'm 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 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'd now like to open the call to questions.

[Operator Instructions] Your first question will come from the line on Kurt Hallead representing RBC.

I had a -- first, I had -- you as only -- your last comment there, Mark, about customers starting to talk about increase in building 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 your service companies are suggesting otherwise. So I'm just curious as to maybe what is unique about these customers that are gaining an increase in activity. In your history, have you seen these customers as apparently 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 could provide would be great because we're just now picking up on any of that -- the companies that we talked 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 sort of 2 sets of customers when oil prices where around the $80 and potentially looking like they could go lower than $80, there was huge amount of fear and concern that was provoked as the price of oil got to $90 and in the state around $90, and 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 price -- as the price went -- as you know, from under $2 for a brief moment to kind of 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 would you have." And we're engaged in those conversations. Whether those customers are trend leaders or exceptions, it's hard for us to know. I mean, there's just no way for me to really do much except to kind of 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 in the -- just in that context to 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 side, you would breakdown between oil major integrated oil companies versus large E&P and small E&P?

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

Yes. 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-capped E&Ps, some integrated and some of the average utilities. At this point, the private sites combined with a small public is right around 40% of our total revenue, 60% is going to be -- 60-plus-percent is going to be with the big partners, frankly.

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

Kurt, I think that about trying to control the things we control. As a management team, we're constantly looking at it in 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'll -- 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 were, 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?

Right.

Your next question comes from the line of Joe Hill representing Tudor, Pickering. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Of the $300 sequential day rate hit, how much of that is due to the mix effect of the standby rate?

It's approximately half of it. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: All right. And then, what are your current thoughts on your 2013 capital budget at this point?

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 newbuild rigs a year for the last 3 or 4 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 out. 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. Hope that adds a little color to what we're thinking part. 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. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, Doug. If I I'm going to tell you that, say you are probably only going to get 5% to 10% of a 25 Apex newbuild 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. I mean, when you said we'd only get 5% contracted, my immediate reaction is well tell me what the day rate is for the -- both the 5% and the 95% because that, to me, what your expected the rate is over a reasonable course is what, in effect, should I think determine what you think the economics and payback are to 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. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay, Mark. And then finally, for me, could you guys kind of compare and contrast what you're seeing in Appalachia, the Marcellus versus, say, Texas, in terms of frac demand and customer behavior?

Yes, 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 earlier in the year, there was no question on 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. We are encouraged by gas prices creeping up again, we are having customers that are starting to think again about getting back to work out there. I think the big shift this last quarter has been primarily the flood of equipment and crews and people that have come into the oily market. 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, were 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 netting and kind of 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.

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

Yes, Robin, I think that's fair to say. I mean, 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 standby 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. In a lump sum buyout, it usually means that they've thrown up their hands and kind of given up hope that they're going to put the rig back to work. In our case, with the rigs going on standby, we hope these rigs will actually go back to full operations before the term contract is expired.

Yes. 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 contract out of 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?

We think this -- firstly, we think the spot market is very, very strong for these rigs and that the demand for these rigs is still quite strong. The thing that's perhaps changed is the willingness of customers to sign 3-year term contracts. Now we have not made a decision as to whether we will put them out in the spot market if they don't have contracts, we're going to see where -- how the market develops, firstly. No, 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 under those kind of 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 are -- meet our capital requirements.

I'd also like to point out that many of the rigs still to be delivered this year are much later in the year, including Q4. And the last 2, 3 quarters, even in a somewhat market that's been difficult to sign term contracts, we'd still been able to sign 2 or 3 a quarter. We do expect to sign additional contracts before the end of the year and before these rigs actually go out for the market.

Right. And so Apex rigs that -- whose contracts come up or -- about facing an expiration or renewal, are you typically signing a new term contract or are those mostly going on to a kind of spot basis?

We've had about 50% on both 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 have under the term contract. But I will admit, we are starting to see some of those Apex rigs that are coming through that we are having to put in the spot market. But typically, those are some Apex rigs that are worked 3 or 4 years under a long-term contract, and quite often would go onto a little bit shorter contract when they rollover. And that's not necessarily a bad thing, but certainly I'm not sure we want to be signing long-term contracts at lower prices.

Just one clarifying comment. I may have misunderstood Robin's comments. But to be clear, on our newbuild program, we plan to complete 24 rigs this year, and then we have the 6 that we deferred to early 2013. Of those 24 rigs for 2012, 9 of them I think, pleaded. Up to 24, 17 have contracts at this point. So the uncontracted rigs at this point for 2012 is 7. And Robin, I may have misunderstood your comment but I just want to make sure we're clear on where we stand.

Your next question comes from the line of Marshall Adkins representing Raymond James. J. Marshall Adkins - Raymond James & Associates, Inc., Research Division: A couple for me. First, would -- 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 $70 million -- or $150 million minus the $70 million you've already done.

That's $150 million of new fresh authorization. J. Marshall Adkins - Raymond James & Associates, Inc., Research Division: Okay. And am I to read into that, Mark, that your thought at least in the last quarter is that, hey, the best acquisition out there is our own rigs in effect?

Well, Marshall, I -- we thought that the -- 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 buyback our stock and keep -- we're 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. J. Marshall Adkins - Raymond James & Associates, Inc., Research Division: Okay, perfect. Last one for me. Pressure pumping just -- you blew the doors off there. You mentioned part of the reason you did so well was your supply chain, when others are -- or gets holed up and its boorish, so 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 of world? I mean, was part of it regional? And going forward, can we look for expand cost or the 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-à-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 kind of looked at things, and said, is this going to continue, will this get better? One of the things about these big fractors it's 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. I haven't 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 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 more work that maybe others didn't. Now we also didn't move a bunch of equipment around. And any 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 kind of improve our utilization, particularly in the Northeast. Now in the Southwest, a much different story. We're again, we are very well entrenched and I think we're very well-known. We do a good job 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.

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 what our competitors are either doing or not doing, except from the point of view of how it impacts us. J. Marshall Adkins - Raymond James & Associates, Inc., Research Division: And going forward, obviously, we know there's going to be pricing issue for everyone out there. But should we expect some more of a cost tailwind benefit, if you will, from lower guar cost or sand cost over the next 6 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 6 months and 12 months. In our case, I really don't see any big swings in cost either up or down.

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

My question has already been answered.

Your next question comes from the line of John Daniel representing Simmons & Company. John M. Daniel - Simmons & Company International, Research Division: On the pressure pumping, is any of the margin improvement that you had in Q2, is any of pods have lower R&M expense?

John, there's a little bit of it tied 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. John M. Daniel - Simmons & Company International, Research Division: Okay. I just wanted to see if there's any deferral maintenance in the quarter?

No, not at all. John M. Daniel - Simmons & Company International, Research Division: The drop-off in margins -- I'm sorry, the drop-off in margins, yes, for Q3 is that entirely price-driven or are you expecting some cost group to come back? If you answered that, I apologize, I missed it.

It's mostly price driven, and our best guess as to activity. I mean, one of the things, as you know, that hurts you in the pressure pumping business is kind of continuous activity. And when you don't get that continuous activity, you're kind of 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. John M. Daniel - Simmons & Company International, Research Division: 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 worse 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 something close to replacement value? What would be your preference?

John, I don't want to sort of set the pricing and really try to do that. I think you articulate the right question, although I would've 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 prices, what your own prospects are and a host of other questions, all of which are wrapped up together. John M. Daniel - Simmons & Company International, Research Division: All right. Fair enough. But let me, 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 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 thought we can sell those assets, some which were out of the country, without them coming back to compete against us.

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

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

It's interesting, that you kind of put together 2 ideas. I want to sort of 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 buy back stock without that in the future. So while it positively impacted us to doing it, the lack of it in the future wouldn't stop us from going forward. So I hope that's an answer to your question.

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

I have a totally unrelated question that I comment. When you talk about pressure pumping, your margins are double some of your peers and you've got equipment sitting on the sideline. Does that -- is it a utilization game why you can't bring some of that equipment back and still make margins that provide nice returns for that equipment? Is that the fact that you can't get utilization or is it -- you don't want pricing on all your equipment that's currently outstanding. How do you look at the balance between that?

Before I give you the answer from the business side, I'd just like to point out, when you look at margins pressure pumpers, I think we all can serve 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 cost differently across our income statement. Having said that, Doug?

Yes, Brian, I don't know that I could give you an answer. I mean, I guess, both Andy and I would like to take the credit for the fact and with our operating groups that we're just better. But the reality is, I think we are pretty well entrenched in 2 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...

So the probability of bringing back stacked equipment in the next couple of quarters would probably be close to 0, 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're willing to do some replacement value and then your response, you said maybe on a discount replacement value. I just want to clarify that you would not entertain something just at where replacement value cost are right now, would you?

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 kinds of...

Your next question comes from the line of Jim Crandell representing Dahlman Rose. James D. Crandell - Dahlman Rose & Company, LLC, Research Division: I have a question for Andy but, Mark, feel free to jump into if you want to. Andy, you come from a company that strives to differentiate itself technologically as 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 the business where you can differentiate yourself more technology -- technologically speaking in the business. And if so, in what way?

Jim, so let me just speak in the broader sense of what I've seen in the 3 months that I've been here. It's been great to be out in the field and meet with the people and see the operations that we have. On the technology front, on the 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, it's an interesting customers on traditional drilling technology that provides a package that our people can operate very efficiently, and we're seeing some 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 some -- did the procurement from to meet our specific needs in the places that we work. And again, because of the customizations there, I see that there our people doing a great job in being very efficient and very safe in the pressure pumping operations that we're doing. So while Patterson-UTI and Universal Well Services were not getting specific customization with fluid chemistry, with the hardware and equipment that we're using at the well site, certainly there are some unique things that we have there that are benefiting the customers right now. James D. Crandell - Dahlman Rose & Company, LLC, Research Division: And do you think specifically in pressure pumping that because of technological advancements, whether they be in food chemistry or real-time 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 are almost unparalleled in any other business in the oil film?

Yes, and 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. You'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 the difference. James D. Crandell - Dahlman Rose & Company, LLC, Research Division: 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 still got approximately 155,000-horsepower under term contract. And roughly, this is just rough numbers, I guess there's about more than 50,000 fractoring horsepower today that is not. James D. Crandell - Dahlman Rose & Company, LLC, Research Division: And the amount that's under term contract, Doug, is that -- are those really firm contracts? What kind of 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 have 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 it's always going to be a win-win. And it's kind of 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 I think people have all recognized that, yes, these are valid contracts. James D. Crandell - Dahlman Rose & Company, LLC, Research Division: Okay, and then final question, just maybe one more for Mark. And, Mark, do you see in the future, maybe you can address both of the 2 businesses, do you see Patterson, let's just say, over the next 3 to 5 years, becoming a better -- for lack of a 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 that we're conscious of as a management is that every time we think about our business and thinking about expanding it, and we're -- 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 from our perspective, yes, we'd 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. James D. Crandell - Dahlman Rose & Company, LLC, Research Division: Yes, I didn't necessarily mean bigger, I just -- for example, if you -- all the rigs or pressure pumping equipment you had in the Appalachian 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 strategies 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?

Well, we certainly -- we understand the logic of the question, which is that oftentimes that you can have -- lessen your risk and increase your returns by having a more diverse portfolio. And so, having -- and we, in fact, on the rig side, have a very broad coverage spectrum. As you know, in the pressure pumping business, until a couple of years ago, we were only in the Northeast. The acquisition that we did a couple of years ago gave us the Southwest. We're obviously considering the possibilities of expansion geographically, and always have been. But we kind of look in for your -- pick your spots and pick the moments where you're having most, 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.

Guys, most of my questions have been answered. But I was just kind of curious if you could help us understand the location of some of those standby rigs?

I think there is no one sitting on the -- 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 then maybe more broadly just thinking about the different rig classes be it 12,000 horsepower for the 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? It seems to me when I look through at your fleet that the lower and mechanical rigs, particularly out in West Texas maintain pretty darn good utilization.

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

Okay, so that's not more evidence saying that 1,000 horsepower mechanical market than it is anywhere else?

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

At this time, we have had no further questions. I 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.