Good day, and welcome to the Helmerich & Payne, Inc. Second Quarter Earnings Conference Call. [Operator Instructions] Please note that this conference is being recorded. It is now my pleasure to turn the conference over to the Vice President and CFO of Helmerich & Payne, Ms. Juan Pablo Tardio. Please go ahead.

Thank you, Mark, and welcome, everyone. With us today, are Hans Helmerich, President and CEO; John Lindsay, Executive Vice President and COO; and Mike Drickamer, Director of Investor Relations. As usual, all forward-looking statements made during this call are based on current expectations and assumptions that are subject to risks and uncertainties as discussed in the company's annual report on Form 10-K and quarterly reports on Form 10-Q. The company's actual results may differ materially from those indicated or implied by such forward-looking statements. We will also be making reference to certain non-GAAP financial measures such as segment operating income and operating statistics. You may find the GAAP reconciliation comments and calculations on the last page of today's press release. I will now turn the call to Hans Helmerich, President and CEO. And after Hans, John Lindsay and I will make additional comments, and we'll then open the call for questions. Hans?

Thanks, Juan Pablo. Good morning. Well, our second quarter results were somewhat disappointing after such a strong first quarter, where U.S. Land average rig revenues were up and related expenses were down even beyond our own expectations at the time. While the revenue numbers we reported this morning were in line with our expectations, our expenses were driven higher by several factors. On this call, we will talk about those things and work through some of the noise around the numbers for the second quarter, discuss the clearly positive developments announced today and address some of the opportunities we see for the remainder of 2011. During the quarter, we incurred pretax expenses of approximately $7 million, or $0.04 per share after tax. They were unrelated to normal operations. Juan Pablo will provide some additional information related to these charges and to other unexpected quarterly increases and G&A and income tax rate. On the positive side today, we announced new contracts for 8 additional new builds, bringing to 14 the number of awards secured since our last quarterly call. On that call, we talked about a powerful trend of customers shifting their drilling targets to oil and gas liquid-rich plays. And importantly, they are employing unconventional drilling techniques to conventional reservoirs. Increasingly, well designs are becoming more complex and incorporating longer lateral sections. This trend towards greater drilling complexity is particularly well suited to the capabilities of the FlexRig and is reflected in the number of new orders and ongoing interest being expressed by our customers. The opportunity for additional new builds is also being driven by a resurgent energy cycle with increasing energy prices now in particular oil and natural gas liquid prices and the unfolding growth ramp of shale plays. Taken together, these 3 drivers: increasing well complexity, strong…

Thank you, Hans. As announced earlier today, the company reported $99 million in income from continuing operations for the second fiscal quarter, or $0.91 in diluted earnings per share. Included in the $0.91 are $0.02 of after-tax gains from the sale of used equipment and $0.04 of after-tax charges that are unrelated to normal operations and are attributable to the settlement of a lawsuit and unrelated increases in litigation accruals. The mentioned charges, equivalent to $0.04 per share, impacted our direct operating expenses as reported in the U.S. Land segment by approximately $4.8 million and our direct operating expenses as reported in the Offshore segment by approximately $500,000. The mentioned charges also impacted our total interest expense by approximately $1.7 million. Interest expense for the first 6 months of fiscal 2011 was $10 million, and we now estimate that the total for the fiscal year will approximate $18 million. General and administrative expense, or G&A, totaled $44 million during the first 6 months of the fiscal year, after significantly increasing during the second fiscal quarter. The increase is mostly attributable to a growing level of personnel required to support our growth, market-driven adjustments to compensation metrics and a greater level of professional service expenses as compared to those originally forecasted. We now expect G&A to total between $95 million and $100 million during fiscal 2011. Our income tax rate for continuing operations, although higher than expected during our second fiscal quarter, is at this point, expected to be closer to 37% during the remaining 2 quarters of fiscal 2011. Total depreciation expense during the first 6 months of the fiscal year was $149 million and is now expected to total approximately $320 million during the fiscal year. The expected growth is a result of the ongoing success of our new build program. Our latest capital expenditures estimate for fiscal 2011 is $850 million, but the actual spending level for the year may vary depending primarily on the timing of procurement related to the company's ongoing new build construction program. At this point, we estimate that approximately 75% of the mentioned 2011 CapEx estimate will be directed to our new build program, approximately 20% to maintenance CapEx and the remainder to special projects. We continue to expect to be able to fully fund this CapEx program from existing cash and from cash to be provided by operating activities during the remainder of the fiscal year. Our investment portfolio, primarily comprised of 8 million shares of Atwood Oceanics and 967,500 shares of Schlumberger, recently had a pretax market value of approximately $450 million and an after-tax value of approximately $290 million. I will now turn the call to John Lindsay. And after John's comments, we will open the call for questions. John?

Thank you, Juan Pablo, and good morning. The following comments will describe the operational results for the second fiscal quarter of 2011 and the outlook for the third fiscal quarter of 2011 for our 3 operating segments. And beginning with our U.S. Land segment, operating income improved during the second fiscal quarter, primarily as a result of taking delivery of 9 new build FlexRigs with firm term contracts and the remaining FlexRigs returning from Mexico. So accordingly, the operating income from the U.S. Land segment increased by approximately 4% sequentially to $164 million. Revenue days increased slightly more than the 3% sequentially during the quarter, with an average of 198 active rigs, 132 rigs on term contracts and 66 in the spot market. Average rig revenues per day increased by almost $700 per day to $25,640 as the average revenue per day for rigs and the spot market increased by over $1,200 to approximately $24,700 per day. Average rig expense per day increased by over $500 to $12,457 per day. Approximately half of the cost increase is unrelated to normal operations during the quarter, as Juan Pablo discussed. Additionally, almost $100 of the increase was due to higher labor costs, which contractually is a dollar-for-dollar pass through to our customers and was offset by a corresponding revenue-per-day increase. Going forward, we expect to continue to benefit from growth in our U.S. Land fleet. Today, we announced contracts supporting the construction of 8 additional FlexRigs. Including the 6 new build commitments we announced in March, we have a total of 14 new builds signed since our last conference call in January. These 14 new FlexRig commitments totaled 45 signed long-term contracts over the past 12 months. With these new commitments, our plans are to continue to deliver 3 rigs per month…

Thank you, John. And Mark, we will now open the call for questions please.

[Operator Instructions] And we will go first to the side of Mike Mazar with BMO Capital Markets.

Just one quick question. Some of your competitors have spoken about the weather impacts in Q1 Texas, Oklahoma, et cetera. You guys didn't really mention anything about that. Was it a non-issue for you? Or was there something in there as a result of that?

Mike, this is John Lindsay. No, there was really no impact, Mike. I'm sure there were some rig moves that were delayed, but there really wasn't any impact to our overall earnings.

We will go next to the side of Waqar Syed with Macquarie.

In the past, as you mentioned that you've built at the rate of 4 rigs per month, is it possible to increase from 3 rigs a month to 4 rigs a month anytime soon? And do you see demands for 4 rigs a month going from 3 to 4? Is that a supply chain issue?

Waqar, this is Hans. I think the driver is what you mentioned in your question. It's been, for us, a demand pull model where we've had sponsorship from customers. And they have, in essence, set the pace and what our cadence is. I think we were pleased to be able to maintain the 3 rigs per month that we kicked off in January. And we have the full supply chain support for that effort, and we mentioned we see that going on through the rest of the year. Your question is, could you respond to demand that would drive 4 rigs per month? I think, like you've mentioned, we've historically been able to do that. Part of the balancing act is going to be from some of those learnings, not only hitting on the right cadence in terms of demand, but also finding the sweet spot in terms of efficiency and in terms of cost. So I'm not trying to hedge so much as to say -- as the visibility improves and if demand would continue to ramp, we could be responsive to that. But it has, as you know, lots of moving parts and considerations.

Now some of your competitors are reactivating the older rigs. And even on that area, 1,015 horse power, now there are not that many rigs in the inventory that are left. Would it not be -- at this point, wouldn't it be more rational to maybe just expand capacity to 4 rigs a month?

Oh, I don't think it would queue off of the conventional rig space as you've suggested. I think it's going to be some of the dynamics that we talked about and you've heard us talked about for a long time, which is the customer wants the right tool for more complex well designs. And we've got a robust order book now. We feel good about that continuing forward. It really won't be, I think, so much tied directly to what's occurring in the conventional SCR space.

Okay, but do you have this supply -- from the supply chain side, do you feel comfortable that over the next 6 months, if demand shows up, that you would be able to increase capacity or no?

Well, I think we've got the best supply chain effort in the business. And our guys do a great job of working that. That's not to say there won't be challenges. And I think some of those challenges are being reflected in orders and production that you're hearing from other industry players as they move deliveries to the right. And again, that's why we emphasize the 24 deliveries that we've already accomplished on time and on budget. So that's going to be a good marker for people to pay attention to and watch, but I like where we are on our supply chain. And our guys are confident that we're going to be able to respond to customer demand.

Now on a different note, in Argentina, I mentioned that there's some labor issues. It appears that, that's kind of a recurring issue. It happens with fair regularity. Do you have any interest or are you considering moving those rigs to another market? Or right now, you're kind of committed to that market?

Waqar, this is John. Those rigs, those 4 rigs that we discussed, are all on long-term contracts. And so, I mean, obviously, eventually, those terms will expire. But as of -- for right now, they're still several years down the road.

We will go next to the side of Tom Curran with Wells Fargo.

Hans, I'm curious, looking back over the last 2 quarters worth of Tier 1 new build awards, how many of those were deployed outside of shale plays?

Well, I'm not sure that there were any. John, can you think of...

I think there's been a few, Tom, that have gone to the Granite Wash. But I'm not coming up with very many. Most of those are -- well, now I take that back. There's been several new builds, and I don't know what several, exactly how many that this. But several have gone to Permian that are not necessarily unconventional shales or unconventional plays in general. They're more conventional reservoir that, in some cases, they're being exploited in an unconventional way with horizontal drilling. But they're not unconventional.

That's exactly what I was referring to. So could you quantify how many actually are, have been deployed in the Permian, doing horizontal development of conventional reservoirs?

I probably could, eventually. I don't know that I could right now. Yes, it's really hard for me to quantify at this point, Tom. But we could get with you off-line. Mike could get with you off-line on that. But I think it's significant in that. And it's not just new builds. It may be that there's a much larger percentage of rigs that have been transferred out of some of the unconventional pure gas plays that have been moved in. For instance, we have -- all of our Flex 4Ms now in the fleet in the U.S., with the exception of 2 we have out in California, they're all in the Permian today. Those are super singles that are really designed to drill in a 6,000- to 12,000-foot range. And they're in there doing a lot of that Wolfberry and Sprayberry work that, historically, was done with a conventional rig, a conventional box-on-box rig. But in some cases, they're still -- our FlexRigs are still doing vertical work. But in a lot of cases, we're seeing that the customer has taken that traditional well path and now drilling a horizontal well. And of course, as in all of these plays, they continue to try to reach for more lateral.

And is it your sense as ever more of the conventional drilling shifts to the Mitchell method for development that the preference will remain to do that with Tier 1 class rigs? Or have you had customers express an interest in potentially upgrading some of your Tier 2 rigs, including those that you just sold in lieu of a new build contract?

No, I think it's definitely -- from our perspective, it's going to be AC drive rigs that are designed to move efficiently. And whether that movement is on a well-to-well with a conventional move with rigs -- or pardon me, with trucks, or if it's a multi-well pad arrangement where we're drilling 3 to 6 to 10 wells on a pad. And so, no I -- again, I think one of the things to keep in mind, because of the success of the AC rigs as cycle times increase or improve and your rig move cycles happen more frequently in a year, it doesn't bode well for a conventional rig upgrading to adding a top drive and adding additional components because it helps on the drilling side but it delays or it extends the length of rig moves. And as the cycle time get faster and faster, the rig move plays a bigger and bigger part of the total well cycle.

So just to add one thing, Tom. If you go back 5 years and look at a time when proportionately we had more FlexRigs targeted and engaged in vertical type wells, we still were enjoying a demand shift and a recognition of the impact of better and better efficiency. So I think, like John says, that the trend is in place and, I think, empirical now on what the customer wants.

I think one other driver that I think continues to be a hindrance to upgrading older rigs is, if you'd look at the day rates that those contractors are able to command with those rigs, I think what you'll find is a pretty low $17,000, $18,000 a day, day rate, which, with the investment that's required, that's not a very good return on your investment, as well as the challenge for them to get a term contract associated with that new investment dollars. So I really think there's several barriers to reactivating a lot of those older rigs.

You made some cogent points there, each of you. Shifting gears here, internationally, looking to 2012, just based on the indications you have right now, conversations you're having, the opportunities you feel most confident about, how much could we see your contract account grow by the end of 2012, off of where it is today? How many incremental rigs could we see deployed across your existing international markets? And if some of those would be in new markets, maybe an indication of where they'd be?

Tom, I think that there's some pause today with what is happening in the Middle East and some of the uncertainty in international markets. It's a little bit hard to track because I think there's some positive trends certainly with oil prices and the need for additional drilling and for longer term. That drilling being very suited to what we do with this kind of backdrop of uncertainty and watching the ongoing unrest that you have. So it's harder I think today than 100 days ago to be able to say with certainty what the answer to your question is. It's a good question. We think that some of that moved to the right. It doesn't fall off the cliff. But you're seeing customers -- or at least we are, where they're pointing back to North American opportunities and, if you will, ramping that up. And so we're a beneficiary of that too. So as you know, we're committed to looking for opportunities internationally, but I think they get moved to the right some, and the net of that helps drive further North American advances.

Okay, I appreciate the color. I'll turn it back.

Thank you.

[Operator Instructions] We will go next to the side of Arun Jayaram with Credit Suisse.

I wanted to pick your brain a little bit as, John, what you're thinking about some of the conventional rigs that you've had stacked for a while? Are there opportunities or customers asking you to reactivate those? Or will the focus continue to be on this increasing your leverage to new builds and FlexRigs going forward?

Well, I think you summed it up with our customers asking -- I mean, what we're seeing, as evidenced by the new build commitments, what we see our customers really wanting, FlexRigs. Obviously, their performance is much better. From our perspective, the challenge is, as I mentioned on the earlier question -- I mean, as you begin to look at our competitors and what type of a day rate they're able to command and the investment that's required to reactivate the rig, that doesn't turn out to be a good investment. And again, in addition to that, a lot of customers are not going to be willing to commit to a term contract for an upgraded conventional rig. On the other hand, they are willing to commit to 3-year terms on FlexRigs. And again, we're just speaking from our perspective, from the H&P perspective. We just don't see a lot of customer demand. Now that's in today's market. That's in today's environment. That's very high oil prices, but very low natural gas prices. And if you were to see a pickup in natural gas prices, that would go above $5 or above $5.50, the game could change. But again, who knows? And who knows when natural gas prices are going to improve?

Arun, I think I'd just add to that. One of the nice things we find is, we're solving for something over 10% of our fleet. I think if 2/3 of our fleet was comprised of conventional assets, we may take a different tack. But we voted, and as you know, over the years, we voted for a certain view of the future and what type of installed asset base we want to serve customers going forward. And so it gives us some more flexibility.

I get you. So as we think about modeling, the rig count gains going forward, it's almost all going to be just new builds. Is that a fair comment?

Yes.

Okay, John, I also wanted to comment. You mentioned in your remarks that day rate growth is slowing. Is it still increasing? Or can you give us some numbers around that or what -- you made that comment, so I just want to understand a little bit more.

Well, no, it is still increasing if you look at the average -- the average spot market pricing is about $1,000 less than the overall, our overall rate in average. And so there's still some pricing. But if you look at leading edge pricing, there's still some rigs that we have, and of course, FlexRigs are going to command higher pricing than Flex 4s and Flex 1s and 2s and so on. There's still some of those rigs that are not up to the leading-edge pricing. And so there's some pricing power there. But again, I think in general, when you have -- no doubt it's a very strong market and oil prices and liquids are driving that, but you still have a very soft, very weak natural gas price, which I think has some influence on keeping the business from being the real frothy business that we saw in 2007 and through 2008.

Okay, last question, John. What exactly is going on in Argentina? And then when do you think things will normalize?

Well, I wish I could tell you exactly. That's a good question. I mean, it's a labor union strike that, really, we don't have any control over. I think the country in general has shutdown in an overall strike in a lot of respects. And we get some indication, it sounds like maybe that's beginning to come to an end. But the reality is, since we've been in Argentina, in this particular area where these 4 rigs are working, we've had a lot of labor union issues and a lot of strikes. And it may only be a day or 2 in some cases. This one has been extended. But obviously, as you can imagine, it's very disruptive. Now I will also say that in other parts of Argentina and other states, that we haven't had those types of strikes. And we have a very good labor relations. And whenever I say we, I don't mean we H&P. I mean we, the oil and gas industry in general. So to just generalize Argentina, I'll just say that all areas have it. Typically, we've seen that they haven't. But this particular area does.

Okay, I've read it's been about a month or so, and it looked like it's getting close to finishing. But it sounds like it's not.

We get some indications that we're close to the end on this particular strike. Again, this one has been more difficult than others. What we're hoping is that eventually, there's some common sense injected into the situation, and we can come to some kind of a resolution where we can continue to -- we, as an industry, can continue to move forward and make progress. Because again, it's very disruptive.

And we will go next to the side of Robin Shoemaker with Citigroup.

I wanted to just clarify on the cost side of things here. You're expecting actually your second quarter revenues to be -- average rig rate to be higher. It was. And then you're expecting rig cost to be flat and they were up. Was that the nonrecurring items that drove up the average rig costs?

Yes. Well, there was about $350 of the $500. About $170 was related to the $4.8 million that was related to a $0.04 that I mentioned. But in addition to that, there was $100 or so that was a labor charge. That is a pass through, so we had a corresponding revenue increase. So that would also -- when we talked about -- in the last quarter that we expected the model flat, obviously, if you've got a labor increase, you're going to have a pass through. And then these, what we would consider non-recurring or non-operational type, would have been outside of that. It's really about $100 to $150 on the operations side.

And you indicated that for the current quarter, that you'll see a $300 or $400 increase in revenue per day. And is there an expectation that cost will be similarly up or flattish with the second quarter?

Well, in my comments, I've talked about -- I mean, the fact is, we had a labor increase. There's potential for other labor increases. I don't have any one particular area. Right now, I would say, "Hey, I know we're going to have one here." But when you look at the growth in a lot of the areas that we're working, it's massive rig count growth. And a lot of the challenges with some people's growth is, obviously, personnel. That has a tendency to drive cost increases on the labor side. Again, that'll be a pass through. But just in general, I think there's potential for oil field inflation as more and more rigs are working and just the general cost of goods and services continue to go up. So we believe it's going to continue to trend higher. I can't tell you if it's $100 or if it's $200. But I think cost in general will continue to trend higher. And that's what we've seen in the past.

Yes, okay. Can I ask you about the cost of building a FlexRig? Has there been any upward pressure on that?

Robin, this is Hans. I think we're starting to see segueing from John's answer about just general oil field inflation. We're starting to see the front end of that. I think we've been able to take what might be 1 or 2 percentage points that would include steel and some other costs. I think we've been able just to continue to make progress on our efficiencies in manufacturing efforts such that we've kept those cost, overall, flat. So we're pleased with that. And as we say, we'll just have to watch and see where the demand is and how much oil field inflation shows up.

Okay, and that would come in the rig components that you're purchasing, the mud pumps or whatever?

I think you'd have to look at all aspects in terms of labor involved there, raw material cost, steel, other pieces of the puzzle.

And the contracts that you're signing on the new builds, is the preferred term 2 years now or 3? I know that you've done both, I think.

Robin, we're typically in a 3-year term contract. Occasionally, we'll have a 2-year. But typically, we're looking at 3-year term contracts on our new builds.

Right.

[Operator Instructions] And we will go next to the side of Pat (sic) [Scott] Gruber with Bernstein.

It's Scott Gruber. Just a few quick questions here. Can you update us as to where the leading edge is for the Flex 3s leading-edge spot rates?

Scott, it is a range because of obviously working in different areas. But it's a mid-20s to a high 20s depending on the area that we're working. And as we've kind of said before, for competitive reasons, we're not going to spell it out too much more clearly than that. But it's kind of in that range.

Okay, and then do you believe that you're still maintaining a spread of a few thousand dollars to your competitors within the high-efficiency market? Historically, its been late, not only to the FlexRig design but also superior operating efficiency, in part given your longer experience operating the high-efficiency units. With the competition now having a few years under their belt operating similar units, are you expecting to see some compression in that spread?

Scott, I can't recall in recent memory, or any memory, where we've gone head-to-head with a competitor for new build work. AC drive work where they've gotten the rate or the term, especially the rate that we've bid. I mean, we obviously don't win all of it, that we get our fair share. But when we do lose, we typically have a pretty good indicator as to what the competitor has bid and what they win at. And I have yet to see one that is in the same range. I haven't seen it. I don't recall that ever happening. I don't think there's any doubt that our competitors are getting better. Obviously, when they were new to the new build game, there's been some learnings. But we've been at this for over 10 years, and I think we do a very, very good job. And we're not standing still. We're not at the same level of performance we were 2 years ago. We continue to improve systems and processes. So I'm encouraged. Again, I think give those guys credit. I think they're getting better. But as we've said, we think we can build a better rig for less, and we're able to charge more for it not because our customers -- I mean, our customers are willing to pay for it because of better performance.

Okay, great, that makes a lot of sense. And then on the contracts you're securing for the active units, what types of term are you able to secure broadly on average? And how has that changed over the course of this cycle?

You're asking about rigs that are either rolling off of term, or just rigs in general that are in the spot market that might account -- an operator might put on term?

Right, both. Non-new build term contracts. What type of term are you able to secure?

They're usually 1 to 2 years. I mean, we rarely commit a rig to less than a year. We would just as soon go ahead and play the spot market. But it's generally a 1- to 2-year timeframe. And that's really, in most cases, not driven by us as much as it is by the customer. The customer has a drilling program that they know they're going to have in a certain area. They've got a complement of rigs. They like the rigs, and they want to make sure they can keep those rigs. And a lot of those same customers are customers that continue to order new FlexRigs, and they're growing their fleet in particular areas.

And has that term been extending some of late, given the strength in crude prices?

It seems like -- yes, I think we're probably, in a lot of cases, more than 12 months. And the pricing has improved. We obviously have more term contracts on average for 2012 as we announced today. We're encouraged by that. So there seems to be -- again, I think customers want to make sure they got quality rigs and they can be assured that they'll have those rigs through their budget cycles.

We will go next to the side of Janice Rudd with Pritchard Capital.

I saw that you sold 3 conventional rigs and was wondering which 3 had crossed off the list here? And if you can give us any color on the proceeds, when the last time any of these rigs worked was and who the buyer might have been?

Well, Janice, we have a bit of a confidentiality as far as who we sold it too and what the pricing was. As far as the types of rigs we sold, one mechanical, 1,000 horsepower mechanical, 1,000 horsepower SCR and then a 2,000 horsepower SCR.

Can you tell me, on the gain you took for the quarter, how much of that was related to rigs versus the stuff that you'd sell every quarter? The accounting number? Whether it was a gain or a loss?

Janice, can you expand on that question? I'm not sure I understand. This is Juan Pablo.

You said that there were $0.02 of gains in the quarter. I was just wondering how much of that was from the rigs versus drill pipe or whatever, auxiliary equipment that you sold?

Oh, it's about half of that, Janice. But again, we're not going to expand it much further on that.

And PEMEX is going to be -- or has some tenders out for a platform rigs. Are you interested in going back to work for PEMEX?

Well, Janice, when we were in Mexico, we were actually working for Schlumberger through an IPM arrangement. So our customer in that case was actually Schlumberger, and their customer was PEMEX. Yes, we're familiar with the tenders. But no, we really don't have the rigs available for that type of work.

It tends to be small.

Yes, it tends to be. It doesn't really fit our fleet profile.

And we will go next to the side of Steve Marrs with Citizens Trust.

Gentlemen, earlier a caller discussed about the duration, if you will, that you folks can operate at 4 rigs a month. Could you maybe go into that and then give a little greater detail?

Well, I think the issue is driven by a couple of things. One, we've been in a position where -- and it's somewhat in contrast to our competitors. Instead of just announcing what new build book is going to look like, we're really responding to customer demand, and then they are contractually sponsoring that effort. So part of it is a demand-pull driven factor. Then more and more, I think people are paying attention to supply chain issues and long lead time items and just the ability to organize and coordinate a construction effort. And so I think we're trying to make a point that our supply chain management effort, we think, is very strong. And our guys are on top of that. It allows us to be able to forecast a 3-rig-per-month cadence through the rest of the year. And then we're balancing some of the things we're talking about now, the demand and the supply chain issues going forward into '12. So we don't really have lots of visibility or additional comments on what '12 unfolds like.

Okay, but if things were -- this were wonderful for you guys in oil and natural gas market that -- I guess my question is, could you folks operate at 4 rigs a month indefinitely?

Well, the last time we were at 4 rigs per month, we sustained that effort for 12 months. And what slowed it down was customer demand. So I think we're going to find a way to be responsive to what our customers are wanting.

Okay, thank you for the wonderful detail.

Thank you.

Thank you.

And we will go next to the side of Josh Jane [ph] with Simmons.

My first question is, would you be willing to disclose where the 19 new builds are headed, that are due to be delivered by the end of the year?

I think, just in general, Josh, Eagle Ford, Cana, Woodford, Bakken, most of those are directed towards oil and liquids-rich plays. But that's kind of the overall. If you look at the 45% in general plus the 65%, 70% of those, are in the Eagle Ford, Cana, Woodford, Bakken and probably California and the Permian.

Okay, that's helpful, thanks. And secondly, with respect to new build pricing, I assume it's still in the high $20,000 per day range? Would you say that, it's held there in that range and that we would need a rebound in the gas rig count to sort of move pricing higher than that?

Oh, I'm not sure that it would be so clean a break on what happens on gas prices. I mean, I think one of the things that, I hope, people are paying attention to, because we're in a brave new world where we have, for the first time in over, I think, it's 15 years, more rigs running directed towards oil than gas -- and so it is a significant backdrop, and it suggests that -- depending on your outlook for world energy prices and oil prices and lots of other issues, it looks like you could have increased demand in a less secular, less volatile forward cycle. So those things are all unfolding. And I think the industry's trying to get their arms around that. So I mentioned in my comments that improving gas prices could be additive and could be a layer that would add on to that type of demand if we could see gas prices reverse and gas-directed rig counts stopped declining. So I don't know if that helps, but I think we're in kind of a new area in terms of so much of the industry's fleet being directed towards oil and liquids-rich plays.

That's very helpful. I'll turn it back.

Thank you.

And gentlemen, it looks like we have no more questions at this time.

Thank you very much, Mark, and thank you, everyone, for joining us, and have a good day.

This concludes today's conference. We thank you for your participation and hope that you have a nice day.