Patterson-UTI Energy, Inc. (PTEN) Q2 2007 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the second quarter 2007 Patterson-UTI Energy, Inc. earnings conference call. At this time, all participants are in a listen-only mode. We will conduct a question-and-answer session towards the end of today's conference. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. On behalf of Patterson-UTI Energy, I would now like to turn the call over to Mr. Jeff Lloyd. Please proceed.

Thank you. On behalf of Patterson-UTI Energy, I'd like to welcome all of you to today's conference call to discuss the results of the three and six months ended June 30, 2007. Participating on today's call will be Mark Siegel, Chairman; Cloyce Talbott, President and Chief Executive Officer; Doug Wall, Chief Operating Officer; and John Vollmer, Chief Financial Officer. Again, just a brief 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 such forward-looking statements. Important factors that could cause actual results to differ materially include but are not limited to declines in oil and natural gas prices that could adversely affect demand for the Company's services and their associated effect on day rates, regularization, planned capital expenditures, excess availability of land drilling rigs, adverse industry conditions, difficulty in integrating acquisitions, demand for oil and natural gas, shortages of rig equipment and the ability to retain management and field personnel. Additional information concerning factors that could cause the 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 on the Company's website as well as on Edgar, the SEC's website. The Company undertakes no obligation to publicly update or revise any forward-looking statements. And now it's my pleasure to turn the call over to Mark Siegel for some opening remarks to be followed by questions and answers. Mark?

Jeff, thank you. Good morning and thank you for joining us today. I hope that by now you have all had an opportunity to read our earnings release which was issued earlier this morning prior to the opening of the market. Before responding to your questions, I would like to take a few minutes to review briefly the results for the three and six months ended June 30, 2007 and to indicate some of the highlights from the just-completed quarter. To summarize, net income for the three month period totaled $140 million or $0.88 per share compared to $172 million or $1 per share for the three months ended June 30, 2006. Revenues for the just-completed quarter were $523 million compared to $637 million for the second quarter of 2006. Net income for the six months ended June 30, 2007 totaled $255 million or $1.62 per share compared to net income of $331 million or $1.91 per share for the first six months of 2006. Revenues for the six month period were $1.1 billion compared to $1.2 billion for the first six months of 2006. Net income for the three months ended June 30, 2007 includes the recognition of a pretax net recovery of $41.9 million or $0.17 per share after-tax from the receiver who was appointed to seize assets under the control of Jonathan D. Nelson. Net income for this period also includes a pretax net gain of $16.5 million or $0.07 per share after-tax from the disposal of assets resulting primarily from the sale of certain oil and natural gas properties. Excluding these items, net income for the second quarter ended June 30, 2007 totaled $102 million or $0.64 per share. Turning to our operations, average revenues per operating day during the second quarter were $19,410 compared to $20,350 in the first quarter of 2007. Average direct cost per operating day decreased to $10,570 compared to $10,720 for the first quarter of 2007. For the quarter ended June 30, 2007, the Company had an average of 237 drilling rigs operating, including 235 rigs in the US and 2 rigs in Canada. This compares to 255 rigs operating, including 243 in the US and 12 in Canada for the first quarter of 2007. We estimated that our July rig count increased to 248 average rigs operating including 239 in the US and 9 in Canada. We expect rig count to remain at this approximate level for the balance of the third quarter and for the decline in day rates to moderate. We expect our revenues per operating day to average approximately $18,800 and our direct cost per operating day to average approximately $11,000. While mild weather conditions have contributed to a recent decline in natural gas prices, we believe that a substantial increase in natural gas wells in North America will be needed to meet increasing demand and to offset steep decline rates. We continue to use our strong balance sheet and cash flow to invest in our rig fleet and to return excess capital to our shareholders. We are confident this strategy will serve our Company's shareholders well in the future. Consistent with this strategy, over the last several years we continued our program of upgrading our rig fleet and other equipment. During the first six months of this year we reinvested more than $300 million in our businesses. In anticipation of increased demand, we have added 12 new or like new drilling rigs to our marketable fleet so far this year and expect to add approximately five additional rigs during the remainder of this year. We also announced today that the Company's Board of Directors has approved a stock buyback program, authorizing purchases of up to $250 million of the Company's stock in open market or privately negotiated transactions. This stock buyback follows the program... follows the buyback of $450 million of our common shares in 2006 and it demonstrates continued confidence in the Company's strong cash flow and our continuing commitment to deploy capital in a manner beneficial to shareholders. Also, the Company declared a quarterly cash dividend on its common stock of $0.12 per share to be paid on September 28, 2007 to holders of record as of September 12, 2007. Lastly, we'd like to express our appreciation for the hard work and dedication of all of our people in each of our business units and to thank them for their efforts. At this point, I'd like to open the call for questions. Question and Answer

[Operator Instructions] And we will wait one moment while the list of questions compiles. And your first question will come from the line of Emily Horan from Raymond James. Please proceed. Emily Horan - Raymond James & Associates: Good morning guys, congratulations on a great quarter.

Thank you. Emily Horan - Raymond James & Associates: One of your competitors the other day mentioned that margins may fall by another $1,000 a day by the end of the year. What do you kind of see happening over the next two quarters?

John, do you want to respond to that?

Yes, I think as Mark indicated in the opening comments, we think that the rate of decline on day rates have moderated. And as we look into third quarter our guess is that revenue per day will go down about $600. We don't really have visibility into the fourth quarter so I wouldn't speculate on what will occur there. We just know that declines have moderated over the last few months. Emily Horan - Raymond James & Associates: Okay, great. And then one other question. Your pressure pumping segment did really well this quarter, but larger players in the business are complaining that there's too much equipment right now relative to demand. Is this the case in the Appalachian market too?

This is Doug. Let me respond to that. At the moment we don't see a lot of excess capacity in the Appalachians. A lot of our customer base there is getting very busy with the shale plays and the business there is slightly different than what we see in the rest of the US. So at the moment, we have continued to add some capacity ourselves in that our market to meet the larger shale fracs that we see. And to date, that business is very different and some of the equipment in the rest of the US isn't entirely suitable for that marketplace. Emily Horan - Raymond James & Associates: Great. Thank you so much.

And your next question will come from the line of Arun Jayaram from Credit Suisse. Please proceed.

Hey guys, those were nice results. I have a couple of questions for you. One on the OpEx guidance for the quarter. Your rig count is going up so I generally would have thought that on a daily basis that you could hold your cost kind of similar to Q2. Are you guys being conservative or are there any other increases in cost that you're seeing?

Arun, if you go back to our May conference call, we also thought expenses would be somewhere around $11,000 a day. We did get a little bit of a benefit in the quarter in terms of Workers' Comp costs basically with running... we peaked at about 308, as I recall, rigs running in the US during 2006 and declined to a bottom of about 220 this year and of course it's come back. But with the decline in rigs running, frankly, crews seem to get safer, have less accidents and we had virtually no net Workers' Comp costs in the quarter. I hope that will be true again in the third and the fourth quarter and beyond but I wouldn't assume that, so therefore when you add that back in, you know that adds $250 a day to your operating costs. Getting from there up to the $11,000, we've been activating a few rigs and that has some costs associated with it because those are expensed. We don't have corresponding revenue. So overall, our guess is around 11,000. We might do a little better but that's the estimate that we were comfortable with.

All right, makes sense. Guys, I was wondering if you can update us. I knew you bought some equipment from NOV for the 1500 horsepower like-new builds. Can you comment on where you're at in terms of reactivating those rigs?

Arun, this is Doug again. Let me comment on that. We put together our first of these 15 rigs during the quarter. It went to work in South Texas sort of late in Q2. We are very pleased to date with the performance of that rig and the crew. We're currently looking at completing another couple of these rigs before the end of the year. I would say the balance of them we will be looking at in 2008.

Okay, thanks, Doug. Mark, I've got a bigger picture question for you. LNG deliveries were over 3 Bcf a day, that's a day, and I just wanted to get your thoughts on... thinking about maybe your five-year strategic plan at Patterson. How do you adjust the business model to respond to a competitive threat like LNG in the next decade? Are you going to look more at international opportunities going forward?

Arun, thanks for that question actually. A couple of things come to mind. First, the delivery of increased amounts of LNG during the first half of 2007 we believe is one of those somewhat of an anomalous things because of the weather conditions in other parts of the world have made natural gas very inexpensive and the delivery into the US. That said, long-term we have always anticipated that a portion of the US supply would come from LNG. And we think that portion is going to be important as part of the balancing of the overall supply equations for the US. That said, however, we still believe that land drilling will furnish the lion's share of the natural gas which we consume in the US, that smaller and more difficult in effect the higher fruit on the tree, to stay with an analogy I've used frequently, that smaller bits of fruit higher up on the tree will require many more wells to be drilled. And the trend in which the number of wells has tripled will in effect require greater numbers of rigs and greater deployment of an overall land rate fleet. So we don't see that what's happening in the LNG business kind of in the first half of the year is some precursor to the kind of death of natural gas drilling in the US or anything else. It's just part of the overall supply; an important part but not going to change we think the fundamental dynamics. Having said all that, we are always looking at opportunities both domestically and internationally. We continue to do that. In the quarter we haven't located anything that we thought was compelling and therefore we have continued in our business which we think is healthy and strong.

That's great, Mark. Thanks for your comments.

And your next question will come from the line of Kevin Pollard from JP Morgan. Please proceed.

Thanks, good morning, guys. I wanted to ask you about... one of your big competitors talked last week about maybe feeling like they had been too disciplined pulling rigs out of the market and giving up too much share for their own good. I wanted to kind of, a, get your thoughts on that, maybe you felt the same way. And then kind of the follow-up to that question, your rig counts seem to increase more than the overall rig count, which would suggest that you're kind of regaining some of the share yourselves. And I'm wondering if you've had to get more aggressive on the pricing for that to happen? If you could just sort of comment on the dynamics at play there?

Kevin, before I hand it over to Mark or Doug or Cloyce, I guess I'd like to point out that in the decline in rig counts that we saw from... began a little bit in September of last year but mostly it occurred late in the fourth quarter and the first quarter this year. Best I can do tell, we gave up more rig count than any other driller. And the only other company that gave up much rig count was Nabors. And they gave up similar numbers to what we did based on what we hear them say. So I think we've demonstrated our pricing discipline by stacking rigs to try to keep rates where the Company can get reasonable returns from the capital that we deploy. As the rig count stabilized in the second quarter and for us it bottomed at the first week in April, and began to come back up, we believe in response to higher natural gas prices that began in mid-January, our customers began to drill more. And therefore, more rigs became active in the US. So I think our rig count has followed the demand of our customers and I think they have followed the gas price. To the last question, no, I think by our revenue guidance we had indicated that pricing declines we believe has moderated and we have not cut price in order to get that small increase in the rig count.

The only thing I would add to that, Kevin, is the concept that you ordinarily see some sort of a lag in the drilling business between in effect the margins you receive in a quarter that reflect what in effect the contracting that might have been done 60 to 90 days beforehand. And so we're seeing the impact of it and the guidance that we said in which we said the day rate declines have moderated is also consistent with the numbers that we gave, which are reflective of that, but I don't think indicate a desire to change around in effect market share.

Okay, thanks. And then one last follow-up. Could you give us an update on sort of where your fleet stands in terms of the number of term contracts... or percentage of term contracts that you have? Any changes in that strategy?

Kevin, today we have approximately 70 rigs or about 20% of our marketable fleet under term contract of varying length. By the end of the year we expect this number to be down in the range of 50 rigs working under term contracts. We do have some new rigs coming to the marketplace. We have two new rigs coming in early September that will be under one to two year contract. The other is a three year contract. We do expect some additional rigs including the NOV rigs that I mentioned to you earlier that will be coming to the marketplace. And we're talking to some operators currently about some term contracts for those rigs.

As you deploy the balance of those new NOV rigs, are you typically trying to secure a long-term contract on those?

Kevin, we're really looking at things on rig by rig basis. We decided on the first ideal rig in the marketplace not to take a term contract. We wanted to get the rig to the marketplace, get the bugs worked out of it and we're obviously very conscious of current pressure on day rates. So we've actually... we're looking at it. If we can find the right deal we will certainly look at a term contract but it's not an absolute necessity.

Okay. Thanks a lot.

And your next question will come from the line of Robert Rodriguez of First Pacific Advisors. Please proceed.

Yes, I'd just like to get a little bit better idea about your long-term trend here on your capital spending about where you are right now in your overall plan, given that you're spending at such a high level relative to depreciation?

John, you want to answer this?

Well, yes. I'll start with... just to speak to the year, we expect to spend about $650 million this year on CapEx. And I think we've explained previously, in the middle of 2006, lead-times for almost anything you ordered was at least six months and many things were nine or 12 months. So lots of orders were put out there in 2006 that we're taking in that equipment today. We have a substantial inventory of drill pipe. Off the top of my head it's somewhere 170 to $200 million worth of brand new drill pipe that we're not using but we're confident we can make good use of in the future, resulting in total hire capital expenditures than it might appear would be justified based on activity levels. At the same time, we're finishing up our refurb program and we have begun to put together the NOV rig. With regard to the NOV rigs, that contract was signed as I recall in August of last year. We've put one out, as Doug indicated. There's two more that we're going to embark on putting out. But we're not racing to put those into the market. However, the lion's share of the cost of those rigs was the equipment that was ordered last year that we took delivery of this year. So, I guess where I'm headed there is that the $650 million is not indicative of the maintenance capital necessary to operate our business; that would be a substantially lower number. This is the follow through of orders from last year and also wrap up our refurbishment program and the beginning of new build.

Whereabouts would be your maintenance capital spending now?

I beg your pardon?

The question is whereabouts would the maintenance level of spending be?

And also the amount of equipment ordered from NOV?

The equipment order for NOV on the new rigs is... was about 120 or $130 million. Maintenance capital... you know, to maintain the rig fleet and not... improve it, keep it running as it does runs about $1,100 a day. So that's... such a number is driven by drilling days. So if you have 100,000 drilling days, you're going to have about $100 million or a little over that, $120 million.

Okay, and then last question would be is that with all that you're spending here, can you give us a sense of the hump... we're looking at your hump in terms of capital spending right now. Can you give us a little bit broader feeling as to where you might be, say, in 2008?

Robert, let me say this. It's... I think John's indicated by telling you about the maintenance cap-out for our drilling business at $1,100 a day, and there's comparable numbers in effect to be spent in our pressure pumping business. And to a far lesser extent as well in the fluids business. The capital that in effect keeps those businesses going strong but doesn't in effect add capacity or change the nature of the equipment. What we've been doing... and that was the point of the comment about upgrading our fleet... is really putting significant... devoting significant capital to, in effect, adding a different level of capability to our capacity, for example in our pressure pumping business, to adding capacity and capability with our drilling business. We have some of the most sophisticated newest technology rigs working any where in the country in rigs that we have in effect built for a particular purpose over the last several years. So that's the commitment that management has made to the business and I tried to indicate that in the early remarks. We haven't decided how much more of that we're going to do in 2008. We will actually address that question toward the end of '07. So that's the reason we're hesitant to give you that answer at this point.

Thank you very much.

[Operator Instructions] And your next question will come from the line of Geoff Kieburtz of Citigroup. Please proceed.

Good morning.

Good morning, Geoff.

Just to kind of go back a little, you had said at three months ago you thought margins would come down about $1,300 a day in the second quarter. They obviously didn't. You'd mentioned you reminded us that you had been forecasting in net about $11,000 a day of OpEx per rig. So it looks like the day rate decline came in pretty close to what you've been forecasting. Is that a fair conclusion?

Yes.

And the OpEx is where the real variance is and I think, John, you addressed the issue of Workmen's Comp. But that kind of... that explains half of the variance versus your expectation on cost. Is something else going on there that is either temporary or perhaps structural?

If you go back to the fall, our customers basically indicated that they were going to slow down toward the end of the fourth quarter and thought they'd come back at the beginning of the year. I think we knew and acknowledged that the gas prices... if we didn't have an early winter that might not occur. And initially in 2007, the customers weren't highly active. In fact, in rig count we lost eight rigs a month on average January, February and March. The effect of that was we thought we needed to maintain a lot of those crews to be prepared to go right back to work because you've got to be ready if your customer is going to go to work. And earlier in the year I think there was some inefficiency in our cost structure related to keeping those people, which was a conscious decision. We released most of that excess capacity in the second quarter and got a little bit of benefit from that. The other side of it, though, is when you start activating rigs you produce some inefficiency also, just like you do when you're stacking rigs. So, we think the overall trend for the Company is going to be somewhere around this $11,000 a day cost level until we get to a higher number of rigs running.

And then it would go down?

Yes, I think it would go down. But on the other hand we're making decisions every day just to try to make sure that we're ready to go to work for our customers. A little bit of noise of a couple of a hundred dollars a day up or down in average cost per day is really pretty common in our business.

Okay, so don't read too much into it?

I wouldn't.

Okay. Shift to the pressure pumping for a moment, it was a pretty dramatic increase in the number of jobs sequentially. I understand Doug's comments about Appalachia being pretty stout. But that was... was there something unusual going on there in the magnitude of the increase in the number of jobs?

Jeff, I think the big difference there typically the Appalachians sees a little bit of seasonality in that marketplace in Q2. And this year for whatever reason the weather cooperated and with the volume of work that we saw there, we saw far more activity in Q2 than we normally would in a Q2.

And your sense looking into the third quarter, do you have visibility on that?

Yes, we have a little bit of visibility. The second quarter activity was huge. Frankly, that's the biggest quarter day they've ever had and it was, as Doug mentioned, one that normally has seasonal downturn issues. So can we go up from there in the third quarter which is historically more active? Yes, we believe we can. If I had to guess revenues for the third quarter, I'd guess that they'd move up somewhere toward 54 million. And then of course we almost always have a seasonal decline in the fourth quarter in that business because of less days available to work. And so I would guess you would pull back toward the 50 million level. But activity levels in Appalachia are very, very good right now. I think you know we have a great business up there who's been there since the '70s. And they have a great market position and continue to do a really great job for us.

And staying with pressure pumping, I think Mark made a comment, I just wanted to clarify in regards to the maintenance capital requirements for the pressure pumping business. I thought you said it was comparable?

No, I meant that we also have it, Jeff, that there is some component of spending for the pressure pumping business --

But not comparable in dollar terms at 120 million?

Correct. Comparable in terms of concept.

Got you. And what would you estimate for your total business your maintenance capital spending requirement is? Let's use the 120 for the drilling business. I understand you think about it in terms of active days. But if we take 120 for your drilling business, what is all the other businesses?

I think over a several year period of time for the Company as it exists today would be about two in a year.

Okay. And final question. I understand you have not really formulated your '08 CapEx plan but in thinking about the $250 million buyback authorization, were you thinking that that was something that would be funded out of free cash flow after the CapEx is taken care of or are you willing to borrow to complete that buyback program?

Jeff, just relative to our balance sheet and where we sit today. If we spent the entire buyback now this quarter, next quarter, this year relative to what we'll have on our balance sheet on operating results for this year, we probably would find that we would borrow some money to do that. We believe that we could manage our balance sheet this year, whereby we entered the year with a little bit of debt, paid it off pretty promptly and thought we would end the year at these CapEx levels but ignoring a buyback. It roughly zeroed out. I mean it could be a few million either way. So if all that money got spent, we would find ourselves with a little bit of debt. But as you look forward to next year, what we do on the CapEx side is very dependent obviously on what our customers are doing. But the refurb program which a lot of money has been spent on has been completed. And the NOV rigs, most of those dollars are spent except to activate them, which is $1.5 million or so per rig, which is comparatively smaller dollars. So, short of upgrades, new rig orders and things like that, our CapEx level should come back some if your assume we continue at these same activity levels. So I think that the point there is that with the whole thing spent we'd have a little bit of debt there but that I would think that would be able to be paid off pretty quickly as you look out into 2008.

I think I heard you say two things there, John. I think I heard you say that you're thinking about this buyback as being a this-year event and that you are willing to borrow short-term in order to fund it.

I didn't mean to speak to intent, Jeff. I think I was speaking to the balance sheet only and not meaning to make comments on how we might spend it.

I'm sure, Jeff, that it goes without saying but I'll say it just for everybody else who's listening. Our view about this as we look at the opportunity in terms of what our stock price is on a daily basis when there is a buyback program in place and try to make the best call, the best use of our capital.

Totally understood.

And I'm not going to be more specific than that.

Totally understand. Thanks very much.

[Operator Instructions] And your next question will come from the line of Kevin Simpson from Miller Tabak. Please proceed.

Good morning, good performance in a tough environment. A couple of questions. One, you as a group probably have more exposure to the so-called checkbook drillers and with weaker gas prices, some activities holding up better than I would have expected. Do you think that it's the stronger oil price that's keeping cash flows up? Or are a lot of the customers feeling like... that kind of making a forecast that gas prices are going to firm up here before too long?

Kevin, it's Cloyce. I think that the mom-and-pop operators are understanding the script price of natural gas better now than ever in the history of the industry. And certainly they think that the prices of natural gas is going to firm up in the future. Again, short-term nobody knows because it's a weather call. Long-term it's obvious that we're going to have higher prices of natural gas to drill the wells that are going to be needed in this country to supply the natural gas it's going to need. And I think that some of what we're seeing come back into the marketplace in the last few months for our increased utilization is coming from those mom-and-pop players. Or I like to call them checkbook players but, as you well know.

Yes, just to follow up on that, Cloyce, do you... since you probably know a lot of them pretty well... do you think that... are they using the futures market then?

I think most of them do not use the futures market. Most of the checkbook players do not use it but they're learning to look at the strip, I promise you. Gives them an indication of what they think is going to happen in the future.

And for Cloyce or Mark or John, you said you did take crew capacity down and they let some crew go in Q2. Could you give me a sense or us a sense of what you think your kind of capacity is right now people-wise?

Let me answer that. Let me tell you what really happens in that, Kevin. As you upgrade your other crews and you keep all the people that you really want and need in the industry. And so when you shut down like we've shut down 60, 80 rigs over a period of time, you certainly upgrade the rest of your crew so you still have the majority of the fine employees that we have. Going forward, you just have to go back into the marketplace and get the employees to run the rigs. But we'll take some off of the other rigs, the good employees that we've put on the operating rigs that we took from the stack rigs when you do that. It's a process that's worked real well for us for a number of years, particularly since the 2001, 2002 period when we really had a downturn and then we ramped back up into the high levels we had in 2005 and '06.

Okay, and then one other question. Again, more strategic. There looks like a fair amount of opportunity being generated by the PEMEX. To date you guys have stayed away from that but it looks like there's a... could be a substantial pickup in demand. Would that be... is that a part of the long-term plan to be involved? Or are you going to continue to focus on your current markets?

I think that we're looking at opportunities as I tried to indicate before and without being too specific --

Yes, I'm trying to get you a little more specific.

I understand. And obviously we don't want to discuss what we're discussing with our particular customers. That's just not what we do. We are looking at the opportunities both here and abroad and trying to see which opportunities to us present kind of the best returns as we think about it for our shareholders and our employees. I mean, one of the things that you always are factoring in... and you know this as well as I... that in effect when you're doing business further away from your home base you have to get a higher return to compensate you for the incremental time and risk that you're taking on. And so we're thinking about it but that's about as much as I can say.

Okay. Thanks for that. And that's it for me.

And your next question will come from the line of Jack Fraser of Seamark Capital. Please proceed.

Good morning, guys. Congratulations on a nice disciplined quarter. I may have missed this but I'm wondering if you could address the margin differentials that you're experiencing or expect to experience between refurbs and new rigs? Thanks.

I guess, Jack, I don't see that there's a margin differential between refurbs and new rigs. Frankly, our refurbs are virtually new rigs. Doug, you want to talk about that further?

Yes, Jack, let me comment on this. For the last year or so we've talked about refurbing a number of rigs. In my three months or four months here, I'd have to say that it's almost a little bit of a misnomer. Looking at these rigs personally, they're far from a refurbed rig. I mean there's very few components that are not new. In fact, we really should have been calling these brand new rigs. I'm incredibly pleased with our state-of-the-art walking rigs that we've built for the Rockies, primarily. These are rigs that were designed very specifically for pan drilling. We have seen great enhanced performance from the rigs. I think the operators that we're working for up there have seen significant reductions in their costs. And we're very pleased particularly in these environmentally sensitive areas. So to answer your question, there really isn't a whole lot of difference in the margins between the new rigs and what we call the refurbed rigs. Certainly with new rigs you're going to see some benefit in the short-term from just the fact you're not going to have a lot of maintenance capital. But there are some things with any new rig that you'd have some startup problems sometimes, particularly with new electronic equipment. But very quickly you do see some benefits from operating the new rigs.

So those startup issues don't really reach into what you experience then on a margin basis?

No, not particularly. I think when you look at... when that gets spread out over 350 rigs you really don't see that.

Thank you very much, guys. Again, congrats.

And you have a follow-up question coming from the line of Geoff Kieburtz of Citigroup. Please proceed.

Thanks again. I think, John, you made a connection between sort of what the gas price is or to use Cloyce's, what the gas strip is and what the checkbook operator demand level is. If I could stretch you a little bit, if the strip were to stay at the current level through the coming quarter and you contract business for the fourth quarter during this third quarter, would you expect that that would sustain the downward slope in day rates? Or would that stabilize day rates at something around the level you're forecasting for the third quarter?

Jeff, obviously we don't exactly know. We know that when the gas prices went from $7 to $8 and went well below $6 that customers reacted, and I think it's more than checkbook drillers reacted. We know when the price came back up and went up into the 7's that we saw more activity. And you can see that in our numbers. Exactly what the point is where people drill more or less is a little hard for us to figure right. I know there's been a number of reports done last year that kind of seem to think $6 was around the spot. But we don't really know. We don't do work to determine that. In terms of what the rig count will do, clearly there is a relationship between the gas price, not for a day or a week or even a month but what it does over a period of months because our customers, they plan. They don't do one well at a time, most of them. They do a series of wells. That takes preparation. When the gas price went up in mid-January, we didn't see a reaction of the rig count until April. Again, because they have to plan. These are complicated projects and a lot of people have to be lined up.

I guess maybe I was assuming something there in that question which is that your view that the pace at which the day rate is coming down is slowing is related to the fact that you've seen an uptick in activity since April. Is that a correct assumption?

Well, what we've historically seen... and what we'll see this year and 2008 is yet to be seen... but if you go back and you look to kind of the '97, '98, '99, 2000, 2001 time period and also what happened in the years after that. We know that as the rig count goes up, it gets constrained. The difficulty is that once you stack a rig, it does take a few weeks to put it out and you've got to find a crew and you've got to train it. Because I don't believe any of the drillers keep all their crews if they aren't working the rig. And we certainly don't. And so as the rig availability gets constrained by crews or iron, that tends to move pricing upward. As a result, what kind of happens is when the rig count starts up or what has happened historically, as the rig count starts up, since you're contracting a few months back, prices will continue to drop a little bit during that period. But about the second quarter after a rig count increase, if it continues on up, that pricing will stabilize and then head back upwards. The rig count seems to be for us bottomed in April. I don't know if that is the bottom but it was. And pricing at the same time has moderated to a more stable level. But I just don't have visibility as to whether the price will stay at this level in the fourth quarter or whether it would drop a little more or whether it could go up.

Got you. And a question I think probably for Cloyce. How long can a rig stay idle in the yard before it starts to become a refurb candidate? That is, that it's taking more than two to four weeks to put it back in the field, it's taking substantial amount of capital and a substantial amount of time.

We've stacked rigs for years before it. If you don't rob parts of them, you can put them right back out to work. The rigs that we've refurbed over the last three or four, five years have been major, major refurbing the rig. And I'm talking about rebuilding draw works, changing the pumps out, changing the... making electric rigs out of rigs that were not electric rigs. I mean, it's just a major, major refurbs. To stack a rig that you have refurbed, it could sit there for quite some time and then not require a lot of capital to go back to work.

But I'm assuming the rigs that you're stacking now are not the refurbs but rigs that have not been refurbed. Is that correct?

Sometimes you stack some that have been refurbed. It depends on like a 2000 horsepower rig and if the market is softened for that, particularly in West Texas, and we have some that we've spent millions of dollars on. And actually we've had one that has been stacked for quite some time that just went back to work.

Jeff, just so you know, in finishing our refurb program, those rigs don't necessarily go out at that moment in time if the market is not right. We have rigs refurbed in the last 12 months that have still not worked at this time. The idea is you want to put the rig out there when you can get a good price. We're most of the way through the refurb program. So we believe the right thing to do is to wrap up the project rather than the shutdown and startup times. But we have a large number of rigs that we believe can be put back in two to four weeks. There's also a program... and Cloyce, you might speak to this... when they stack these rigs, they continue to maintain the rigs so that you don't have deterioration of the engine and the pumps and the other components.

Certainly we do that and maintain the equipment. There's a vast difference in a rig that's been stacked for 10 years that you refurbed and we had some of those in our refurb program and one that we have refurbed and stacked for a few months and what it costs to put them back out. You know, 50 to $100,000 would be a lot of money to spend on a rig that you had refurbed and have it stacked for say, six months to a year and then put it back out.

Great. Thanks very much.

[Operator Instructions] And gentlemen, there are no other questions in the queue. So, I will turn back to you for any closing remarks.

We'd just like to thank all of our listeners for their participation today in our call and look forward to speaking with you next quarter. Goodbye.

Thank you, ladies and gentlemen, for your participation in today's conference. This does conclude today's presentation and you may now disconnect your lines. Everybody have a wonderful day.