Patterson-UTI Energy Inc (PTEN) 2006 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the fourth quarter Patterson-UTI Energy Incorporated earnings conference call. My name is Katina and I will be your coordinator for today. At this time, all participants are in a listen-only mode. We will conduct a question-and-answer session towards the end of this conference, at which time you may press star, one, on your touch tone telephone to participate. [OPERATOR INSTRUCTIONS] As a reminder, this conference is being recorded for replay purposes.

Now, on behalf of Patterson-UTI, Geoff Lloyd. Please proceed.

Thank you, Katina. Good morning. And 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 12 months ended December 31, 2006. Participating in this morning's call will be Mark Siegel, Chairman; Cloyce Talbott, Chief Executive Officer and President; and John Vollmer, Chief Financial Officer.

Just a brief mention that statements made today in the 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 dayrates, rig utilization and 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 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, at patenergy.com, or through the SEC's EDGAR system, that's www.sec.gov. We undertake no obligation to publicly update or revise any forward-looking statements.

And now, I would like to turn the call over to Mark Siegel for some opening remarks, to be followed by questions-and-answers. Mark?

Geoff, thank you. Good morning, and thank you for joining us today. I hope that by now, all of you have 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, we would like to take a few minutes to review briefly some of the highlights from the year and fourth quarter ended December 31, 2006. I'm pleased to report that Patterson-UTI Energy has completed another record year, with significant improvements in our contract drilling, pressure pumping, and drilling and completion fluids operations. Total revenues, net income, and net income per common share all set new records in 2006. These record results reflect the committment and dedication of an extremely talented group of employees throughout our organization.

To summarize briefly, net income for the year increased by 81% to $673 million or $4.02 per share, from $373 million or $2.15 per share for the year ended December 31, 2005. Revenues for the 12 month period were up by 46% to $2.5 billion compared to $1.7 billion in 2005. Net income for the fourth quarter ended December 31, 2006, increased by 16% to $156 million or $0.97 per share, from $134 million or $0.77 per share for the quarter ended December 31, 2005. Revenues for the quarter were up by 20% to $638 million compared to $531 million for the fourth quarter of 2005.

We continue to maintain a strong balance sheet, and as of December 31, 2006, we had had $335 million in working capital and $120 million drawn on the line of credit. As of today, we have repaid the revolver and have $0 drawn on the line of credit. During the fourth quarter, we also purchased purchased $83 million of the Company's stock, bringing the total 2006 purchases to $450 million. Our average revenues per operating day were $20,760 in the fourth quarter compared to $20,810 in the third quarter, and our average margins per operating day totaled $10,810 compared to $11,170 for the quarter ended September 30, 2006.

During the fourth quarter we had an average of 290 rigs operating, including 278 in the U.S. and 12 in Canada. This compares to a total of 301 rigs operating, including 290 in the U.S. and 11 in Canada in the third quarter. We activated 28 drilling rigs during 2006, which are predominantly comprised of new equipment. We expect to activate 14 new and like-new rigs in 2007. Almost all of these will be 1,000 horsepower and greater SCR electric rigs. Additionally, when demand increases, we have the capacity to activate up to 14 additional new rigs, which are 1,500 horsepower SCR electric rigs.

The contract drilling results for fourth quarter reflect the effects of warmer than normal temperatures during the winter months of calendar 2006. These warmer than usual temperatures occurred twice in the winter months of calendar 2006, both in the January-March period, and again in the November-December period. At year-end, these warmer than usual conditions had resulted in three points. Number one, high levels of natural gas storage in the U.S. Number two, decreases in natural gas prices, and at year-end, [inaudible] three, a generally bearish outlook for natural gas prices during the short-term. Customers of North American land drillers have reacted by postponing projects and reducing their drilling activities over the last several months of 2006 and continuing into the first quarter of 2007. This decrease in activity caused a decrease in both pricing and profitability in the fourth quarter as compared to the preceding third quarter. Our expectations for the first quarter are for approximately 255 average rigs operating, revenue per operating day of approximately $20,000, and largely as a result of the decrease in operating days, some increase in average costs per day.

Demand for natural gas has recently increased due to the colder winter weather that began in mid January 2007. This recent weather-generated demand has caused the level of natural gas storage to decline significantly, below last year's level and closer to the five year average. With the change in natural gas storage levels, natural gas prices have also recently improved. Despite the recent improvement in natural gas pricing and some recent increase in customer inquiries, we believe our customers' outlook for the short-term remains cautious. During 2007, we do expect that the combination of decreased current land drilling activity, along with high production decline rates for many existing wells, will further reduce the natural gas supply. As the supply of natural gas decreases, we believe that our customers expectations for natural gas prices will become more optimistic. At that point, we expect that the current inquiries will turn into a trend to secure rigs to drill needed wells.

Although it is virtually impossible to predict when our customers' sentiment turns from cautious to bullish, we believe that ultimately, increased land drilling will be required to avoid a shortfall of natural gas. Looking ahead, we see a sustained trend of higher natural gas prices leading to an ever greater number of natural gas wells being drilled. In 2006, the industry saw approximately 30,000 wells drilled, as compared to less than 10,000 wells drilled per year as recently as ten years ago. This level of drilling has been required just to sustain the current levels of natural gas production. We remain committed to an operating strategy in our contract drilling operations that has at its core quality service and an upgraded rig fleet to meet our customers' demands for increasingly complex wells. We believe that this strategy and our strong balance sheet will continue to serve our Company well in the future.

Lastly, the Company also declared a quarterly cash dividend on its common stock of $0.08 per share to be paid to the holders of record as of March 15, 2007, and will be paid on March 30, 2007. At this point, I'd like to open the call for questions.

Thank you, sir, for that presentation. [OPERATOR INSTRUCTIONS] Marshall Adkins, Raymond James.

Good overview there, Mark. Could you give me a sense, are we seeing a stabilization at all in demand for rigs? I know we had a pretty big fall off in January. Gas prices have since rebounded a little bit. Are we still declining in terms of demand for rigs? Or is that stabilizing at all?

Cloyce, you want to try that?

Marshall, I think, and certainly what I'm seeing, is that the customers are reacting to this increase in gas price, and I kind of think it's flattening out. And I would anticipate that we continue to get the drawdowns in natural gas and storage, and the psychology is that the gas prices are going to go up, we're going to see probably a very, very short downturn.

Okay. So you are seeing some sense of stabilization?

That's my opinion, I'll put it that way.

Sure, sure, obviously things could change given the weather we've had already this winter. Costs rose pretty dramatically in the quarter. And if I heard you correctly, you're anticipating a further increase in costs. With the reduction in rigs, why are costs still going up? I would have thought those would start to moderate or even decline a little bit.

Yes, Marshall. When you have a period where the rig count declines, I guess a couple of things happen. If you go back and think back to timing of our third quarter conference call, customers were talking about deferring programs until the first of the year. So as rigs freed up, we kept our crews in place really pretty much through the end of the year, therefore resulting in costs pushing upward. Also to the extent that the rig doesn't stay active, you need to move it to a good, safe location that you can maintain it well. And you really don't get paid for that. So those two items do drive costs up in the fourth quarter. As we look to the first quarter, we're I think we're high-grading all of our crews, trying to not maintain all of the crews, but we're maintaining more excess people than we would in a different environment. So we want to be prepared at least a few rigs worth of prepared for customers to come back and increase their activity.

One other comment on rig count. You asked about what was happening with it. We saw -- lost a few rigs in November. You can go back to our monthly rig counts and see that. And in December and more in January, And I agree with Cloyce's comment about we feel like we're in a relative stabilization. But I think that's a little lower than what we saw in January. Of late, we're running somewhere around 255 rigs, with kind of bouncing around between 12 and 15 in Canada out of that total, for a total of 255. And it seems to stabilize. But I think as we -- unless the U.S. customers react very quickly here, I think we'll see less rigs running in the second quarter in Canada. And net result of that would be that I might see 250 to 260, maybe guess in the middle of that, 255 total rigs running in the first quarter, and it may drop down another 15, 20 rigs in the second quarter.

Yes, normally you see at least a ten rig fall off there.

Right. And really more than that but we're normally running more than that.

Right.

In Canada.

Right. Okay. Staying on the cost scene, your SG&A costs were a lot higher than we were modeling, particularly in the other operating expense category. Can you shed a little light on what was happening there?

Well, really those are two different things. The other operating expense category isn't really a G&A category. What that is for us, the two primary things that fall there are gain or loss on disposal of assets. And we also, given the number is not particularly big, we put our bad debt expense in that number. So for the fourth quarter, bad debt expense included in other expenses was $1.2 million, and then there was a loss on disposal of assets of $4.2 million.

Okay.

For the year, those numbers, the bad debt expense was I believe about $5.4 million. And gain or loss on disposal of assets was about 4. So we had $200,000 of gains going into the fourth quarter, and in the fourth quarter in disposals we had 4.2 expensed. On the true G&A side, there was about a $1.4 million increase in G&A expense related to assumptions for forfeitures of stock options. And with 123R, you make your estimates and you true them up periodically. Fourth quarter we had a true-up. It was about $1.4 million is how much I think that impacted us.

Okay. So I guess more relevant to me and our models going forward, are those other operating expenses trends that will continue? And kind of where should we be plugging SG&A in for the year, full year '07?

I think SG&A would drop in the first quarter from what we saw in the fourth, somewhere in the $14.5 million range would be my guess.

Right.

123R has impacted. If it builds for a little bit, we'll get a little back versus the forfeitures, but then it will increase because you continue to grant shares to people and incentivize them. So that would be my guess there. Relative to the other expenses, periodically we have gains that surprise, relative to your estimates on disposal of assets. And other times we'll have little losses. I don't think it's going to be significant one way or the other. Relative to bad debt, when the gas prices softened, really in kind of in the October time frame, there were a handful of customers that weren't prepared for that. And we increased our reserves in the -- primarily in the third quarter and a little more in the fourth. But we feel that that's well provided for and when the gas prices stabilized, I don't expect any more problems. But occasionally some show up.

And you may even get paid on some of the stuff you reserve for, so it may go the other way, huh?

That could happen.

Great. Thanks. That's good input, guys. Thanks.

Arun Jayaram, Credit Suisse.

Good to see you.

Yes, guys, Ken and I do a weekly sort of the Smith rig count data by contractor. The data clearly shows the down trend in overall land-based activity, which is no surprise. But it also seems to indicate that Patterson has lost some meaningful share relative to your peers starting in October, November, in that kind of time frame. What do you think is driving those apparent share losses, and how do you respond?

Arun, I have a little difficulty with the various rig counts out there. When we put out a monthly rig count, when we do and it's down, I'll get phone calls saying, well nobody else lost rig count. And then in the neighbor's comments when they put our their fourth quarter, they have 41 stacked rigs at that point in time. So I'm not sure how to compare myself to anybody else's rig count, because if neighbors are down 41, and at the time we were down I think 40, there's 80. And Baker Hughes hadn't really moved. I think it was going up. So I get very, very confused by the rig counts. I think I can only take the data points the companies report, and companies that actually run the rigs. We're running somewhere 240, 240 plus in the U.S. And another 13 to 15 in Canada, for a total of 255. We know the neighbors indicated they have 41 rigs that they stack, as of roughly the end of January. You add those two together, you have something north of 100 rigs down in the U.S. I suspect other people are also have rigs down. And I guess the good news we see there is you came out of the winter of '06 with probably more inventory in storage than you wanted, with all of those rigs not working, that means we should see a supply response pretty quickly. Relative to market share, the information we have, and I'm going to hand it over to Cloyce here, indicates that there's lots of people with rigs that are down. Those who don't have rigs down are those who are choosing to cut price.

Arun, the only information that we have is basically from our salesmen. And what they're telling us is other people have rigs down also. And so I don't know what the number is. As John said, the only number we truly know is our number, and we've elected to give that number out on a monthly basis. I think it's a good indicator of what is going on in the industry, and I don't see that we're a lot different than anyone else.

Okay, fair enough. Maybe I could send you the data off line. Second, I was just wondering if you could just provide us your outlook -- near term outlook for your other two segments?

John, do you want to talk about that?

Yes. The outlook continues to be fine. Our pressure pumping business is, as you know, based in Appalachia. That market is doing well. I would expect them to continue to perform as they did in prior year. On the fluid side, I think there we had some pretty unique opportunities in 2006. And we're hopeful that revenues will be similar to 2006. So I think a run rate more in the 35 million to maybe 40 million a quarter is probably more realistic, with occasionally, some opportunities to do bigger things. E&P side, as we -- it's been the case for the last several years, we're not really trying to expand that. And we plan to spend about $20 million drilling wells. And so if I had to guess, somewhere $8 million or so a quarter in revenue. Average it all together, maybe a little better than that is what we would likely see.

Okay. Thanks a lot, guys.

Geoff Kieburtz, Citigroup.

Just looking at the forecast that you've given there in terms of North American activity, Patterson rig count, kind of seen a slowing here, margins have started to come down, it looks like you're forecasting a bit of an acceleration in the decline in activity. Do you expect margins to also accelerate their downward trend with that rig count?

I don't know that I intended to say that there was an acceleration in the decline in the rig count. I think it's relatively, I think, stabilized. The big movement was really January and a little bit in February. With a guess of a rig count, somewhere around 255 in the first quarter, that's pretty similar to what we were running at this point. And you have the seasonal decline in Canada that would cost you somewhere around another ten rigs, from 255 to 245. And until the market goes up, if I had to guess, maybe it was a handful of additional rigs to take us down to maybe 235 in the second quarter. My own guess about the world is that it's a combination of the increased more normal demand we've seen over the last number of weeks on the natural gas usage side, combined with a reduction in drilling that has occurred. Which suggests that as the year goes on, the gas price will firm up and the rig count will start to increase again. My guess would be somewhere in the third quarter, maybe late second quarter. So I don't think we're meaning to suggest that there's a further significant slide.

In terms of the margin side, I think our costs will be higher this quarter. I don't have a real good sense of it. I'm guessing maybe up around $10,500 and I don't see a reason for that to go higher. I don't think we have cost pressures from a labor side or otherwise, particularly in that area at this point in time. We're just trying to maintain our ability to come back when the demand gets a bit higher. Pricing-wise, we have some number of competitors who price wherever they need to, to keep a rig working. We try not to do that. And I think that's evident in our fourth quarter numbers. We try to maintain getting paid a reasonable price for the service we provide, and to do a good job for our customers. But would I suspect that margins will decline some over the first and second quarter? Yes. There will be some pressure on the pricing. I've heard people talk about $4,000 a day. That doesn't seem right to me. It certainly could happen. But for it to drop first to second quarter a couple thousand dollars on the revenue line, I think that's not outside the realm of reason. Maybe it could be 1,000, maybe it could be worse than that, but we would try to hold our pricing as stable as we can. Costs are higher in the industry. We have to get higher revenue per day to operate effectively.

Right.

If the industry improves in the third quarter, you could still see some decline in revenue per day as you go into the third quarter. Because as I think you know, when the rig count starts to move, you're in effect pricing your rigs 30 to 90 days in front of where you are. So when the rig count starts to turn up, you may actually see just a little more decline on a revenue per day basis in the quarter that things go up. So for example, if revenue per day went down a couple of thousand in the second, rig counts dropped just a few more, then the rig count bounced back up in third, you may still see another loss of $1,000 a day on the revenue per day side. But as you went into -- back into an upturn, by the following quarter when utilization moves up, you should see revenue per day also move up, would be my guess. Or that's the history we've seen over the last couple of cycles.

Geoff, I want to say something though, because the way you started the question off about acceleration of decline, I mean, it's just kind of the opposite of what I think we're seeing. We think this is kind of mild in duration and in severity. And I think the thing that's having an impact on it is that the fact that the second quarter, with the usual slowdown because of breakup and so on, has some further impact on it. And so I think you're seeing A and B, B is unrelated to A, and that's causing you to put it together in a way that's not what we're saying.

Okay, all right. That's helpful. In terms of -- I mean, obviously, a lot of this is very weather dependent, and there's a limited amount that you can do to forecast this. But you do still plan to refurbish another 14 rigs kind of as a base case in '07. Are there any circumstances in which you would not proceed with that program?

Pretty much, Geoff, those 14 rigs are well along on their way. What they are is producing rigs, which we think are highly desirable from the perspective of some of the complex wells our customers want to drill. So they are, in effect, particularly fit for purpose rigs. And I think we and our customers are well served by completing those rigs. And so we're planning on doing so.

Will they all be net increments to your active fleet? Or will you be taking some of the current rigs out of the marketed fleet?

I think that depends on demand.

Okay. But at this point, the base case is to keep everything that you are marketing in the marketed fleet?

Yes.

Okay. And in terms of the other 14 that you mentioned as possible refurbs, what are the -- I mean, what's the timeline in terms of making a decision on that?

I think we can make those decisions on a pretty much week to week, month to month basis, depending on what we see in terms of the market firming. John has spoken to the point that we feel that there's a combination of the winter weather that we've now experienced, the withdrawals from storage, and the decline in drilling, which we think all will have the impact of tightening the supply. And that as that tighter supply becomes more apparent as the year rolls forward, then we expect that there will be a pick up in activity.

Right. And how fast -- on those additional 14, let's say you made the decision today. When would you start to see those rigs available in the fleet?

We contracted with National Oil, as you know, to purchase some additional rigs.

Yes.

Those rigs were slated for delivery throughout the year 2007. It takes us some amount of time upon delivery from National Oilwell to put those into service. And so it would be, in effect, during the course of 2007, if we make the decision to put them out to service.

Okay. But, as you said, you can make this decision on a weekly basis. If you decide on certain day one, you could get that rig into service in what, kind of four months?

Depends. We're taking deliveries, as I said over the course of the year.

Okay.

So it might depend very well on what time of the year we're at. If we're at December, and we found ourselves in the situation in which we had gotten all of our rigs delivered from National Oilwell, and we made the decision to put them into service, then something on the order of a 60 to 90 day period of time from that, from the date of decision, would be the date of starting the service.

Got you.

And on the other hand, if you ask me, could we put all 14 to service 60 to 90 days from now, the answer is no. Because we haven't gotten delivery from National Oilwell.

Sure.

And I don't want to create the impression we weren't expecting it either. So I'm not -- not to suggest anything other than these will be delivered during the course of 2007, and we'll have our choices as to what to do with it.

And in terms of personnel, John had mentioned that you're keeping maybe a little bit of surplus crew personnel in anticipation of maybe a quicker pick up in the recovery in the demand picture. At what point do you kind of let attrition take its effect and reduce your headcount?

I think we've done the attrition. I think what John was saying was that as you get to a situation like this, you do two things. One, you try to maintain your most talented employees. And that has some impact on your costs. And you try to maintain some ability to put some number of rigs back into service, so there's some extra crew. So there's sort of two factors, if you will, causing your labor costs in the field for drilling to be higher than they would otherwise be. One is the retention of most talented employees. And two is some ability to add additional rigs as demand warrants.

And Geoff, an example of that would be if you have the tool pushers to run 300 rigs and you're only running 250 rigs, in a longer downturn period, you would demote those people to other levels that would lower their pay.

Uh-huh.

You don't want to do that unless there's a longer downturn. Otherwise, another driller could come along and attract some of your more skilled and experienced people.

Right. I see. And as of right now, your headcount today versus the fourth quarter average is up, down, or flat?

It would be down.

Down. Okay. Thank you very much.

Mike Urban, Deutsche Bank.

Want to talk about the cost side a little more. I know you kind of questioned the rig count numbers out there, so it's tough to get a sense for it. But assuming that that is the right number and the rig count is kind of roughly flat to up, presumably, a lot of the supply chain, including labor, materials, parts all that kind of stuff, is still pretty tight, is it possible in the near term to see costs going up on that basis? You had talked about just costs going up because of fewer operating days, but on apples-to-apples basis or day cost basis, would you still expect to see cost inflation there?

I don't think we know, but I wouldn't expect that. I'll give you an example. At running higher levels of activity, I think the industry was buying lots of drill pipe. I think that based on what we believe is going on out there, I think we're [inaudible] less drill pipe than we were before. One of the funny things with rig counts is you really got to get down to which rig it is. I mean, things that we seen a variety of rigs go out of service, and we believe that other drillers have, too. And if -- I'll just use the neighbors was down 40, and at the same point we were down 40. It's my belief that our rigs are drilling the wells to generate the greater amount of gas in this country than some small rigs that are off in Wyoming or somewhere else. So anyway, and I think that's the bigger iron also. So my take would be that supply chain-wise, we may see some of those things loosen up just a little bit and cost pressures would be lower at this point. Do you agree with that, Cloyce?

I do agree with that. I think that the inflation on the cost side for us is going to go down, similar to what's happening to us where we're providing equipment for the operator.

Okay.

It will certainly flatten out.

Okay. That's helpful. And then the follow-up to that is, are your customers pushing back at all on labor pass throughs, or any kind of incidentals or things that it was easier to get them to pay for when things were a little more robust? And are they trying to, as I said, push back on things like that?

Well, I think there's no pass through issues on labor at this point. I think there was an increase in the spring-summer that probably shouldn't have happened. But we had to respond because that's what some other drillers did. And that was the last labor increase. And I don't anticipate any foreseeable at this point in time, and that's really the only pass through that we have.

Okay. That's all for me. Thanks a lot.

Waqar Syed, Tristone Capital.

John, could you give us some guidance on DD&A for '07?

Yes, I think it all depends on the capital expenditure level, which will partly be driven, at least to some extent, by demand. Although a lot of that is pretty well locked in at this point. I would guess that it would move up kind of quarter to quarter somewhere $3 million to $4 million. Although in first quarter I don't expect it to be a whole lot greater than it was in the fourth, maybe up $1 million or 2. Okay.

And now of the $530 million that you spent on drilling in '06, could you break it down between upgrades and maintenance capital?

Hang on one second. I don't happen to have that in front of me. Okay, in terms of activating rigs, I wouldn't call that an upgrade. I'd call that putting those rigs out. I think we spent somewhere in the $220 million or so range. Actually probably closer to 250. I take that back. That included activating rigs. It included -- probably spent another $15 million in things like iron roughnecks, et cetera. We spent in the range of of $100 million on tubular drill pipe, drill collars, there's some other costs as we've expanded into the Rockies. We had to add more yards. And so we didn't spend a lot of money, but somewhere $10 million or so on real estate, buildings and improvements like that. Of what we consider maintenance capital, that number would be a little bit north of of $100 million. In effect, about $1,000 a day.

Okay. So now, you were spending about, let's say close to about $5,000 per rig day on capital spending, maybe about half of your cash margins. Going forward, you said there's still some availability on your capital spending plans. But can you give us some guidelines on how much of your cash margins would you be spending in CapEx? Or any ranges of in actual million dollars what it could look like for '07?

Well, I have a little difficulty thinking about it the way you did in terms of that we spent $5,000 a day. We activated a significant number of rigs. We can put to work with a customer and a crew, and as of today I think it's 339 rigs. And we expect that that will come to pass. So I don't personally relate that CapEx to those margins. I think on any of the work I've done for the money we spent for rigs that have gone out, we've seen pay backs in the 15 month time frame over the last several years. So I think we've generated the cash flow to cover that. As we look into the coming year at this point, we're fairly locked in in terms of our CapEx for the year. And that's driven by a couple of different factors. Many of the things that we order, you had nine month, 12 month lead times. And so at the end of the year, the vast majority of the capital for the year was really already committed. And I would expect for the year that we'll spend somewhere in the $600 million to $650 million range. And the difference between those numbers is, to a great part, driven by whether we activate the 14 rigs that they were talking about earlier. We can avoid some capital expenditures by actually putting those together at this point in time.

Right.

Go ahead.

And going beyond that, let's say into '08, what do you think could the run rate look like for capital spending?

I think at this point in time for 2008, we really don't have a lot of commitments. We can make changes in our plans there, at least for the next several months, based on where demand goes. Most everything we buy you can get inside a 12 month or less time frame. So at this point, there's not a lot of commitments made. We're in real good shape in terms of either existing or already ordered tubulars. We'll watch the market and determine if we think we need to put orders farther out. Kind of circling back to the CapEx for 2006, I would break it down as follows: In terms of if we bring out all the new rigs, that would cost roughly roughly $200 million. A lot of that will be spent either way, because we've ordered the parts, we will take the parts, and we believe that those rigs will be in high demand in the future. Other rigs that Mark talked about that we'll be activating, costs to go on that would be somewhere around $60 million. Drill pipe, we'll purchase about $80 million. And we could skinny that down some if we choose, but a lot of it is already committed.

We're also going to spend a substantial amount of money on a variety of different upgrade programs. We, over the last many years, but particularly the last two or three years, we have continued to upgrade our drilling fleet, make sure that we're competitive with what our customers need. And upgrade maintenance capital put together, I think we'll spend somewhere around around $230 million this year. And then the other businesses, of course, were particularly pressure pumping. We're going to make close to a $60 million investment there continuing to expand. There's plenty of work, and ability to grow that business as we look toward 2008. Total for all of the other businesses would be around $80 million, which includes pressure pumping at $60 million and about $20 million in E&P. We do not expect to spend a lot in fluids or anywhere else.

Okay. And then if you spend about 600 -- $650 million, then at least by my numbers, you may not have a lot of free cash available. Would you continue with your share buyback programs, or -- by taking on debt? Or would you put it on hold for '07?

We have not made a decision any further than this quarter. We have completed the authorized buyback. As you know, we bought back $450 million worth of stock last year, paid a dividend additionally. Our thinking at this point is to continue that dividend, as you realize from the declaration of a dividend by our Board. And I think what our view is at this point is we're going to watch and see where the business goes. As I think I've said in the call before, we see kind of a mild downturn, both in duration and in severity, followed by a significant increase later in the year. And given that fact, we think that the capital spending plans that we have put in place put us in a good position to be able to go forward. We also think that it's smart, considering the balance sheet that we have. And frankly, I think we've shown our committment to return to shareholders excess cash and excess capital. So our practice from before really shows you what our principles are.

Right. Now, you have been spending in '06 some money on upgrading your active rig fleet. How has already -- how many of the rigs have already been upgraded in the existing active fleet, and how many will be upgraded as you go through the '07 upgrade program?

It's really -- rigs are composed of a large number of components. We are always in the process of upgrading our rigs. For example, every number of years, we put new engines on, or rebuild the engines, and any number of other things. We've been in a program for more than five years of improving our mud systems on our -- all of our -- on any number of our rigs, a substantial majority of our rigs. And we are continuing to do that. We have put in iron roughnecks on a large number of our rigs, and are continuing with that program. And I could go on and on and on about this kind of thing, listing any number of particulars. So the answer is we have in effect improved a very large number of our rig fleet and continue to do so. And basically the committment of capital expenditures in 2007 reflects the fact that we're continuing to do that. And we think that ultimately that by doing so, we will have a fleet that kind of meets the needs of our customers, and continues to meet it.

Right. Now, you have over 400 rigs in your fleet. And we saw about 290 or so work at the top in '06. And '06 was one of the best drilling markets and yet we didn't see your number go over 300. At what point do you say that some of the rigs that you have in your inventory are never going to come back, and so you may decide to write it off? Or do you think that you still have good confidence that all your fleet would be active at some point?

Well, first a small correction. In July and August, we actually were running more than 300 rigs. And that's reflected in our monthly numbers that we put out in each of those two months. So we have actually run more than 300 actual average number of rigs running.

[inaudible] the U.S. number.

Yes, in addition to that, it's important for you to realize that when you put out, and when you run a 300 -- when you run a monthly number of 304 rigs, you're actually running significantly greater number of rigs than that, because of the, in effect, rigs moving, days lost for weather, mobilizations, et cetera. So there's some number of rigs in addition to that. Now, on top of that, I'll turn it over to John in respect to where we are in terms of rig fleet.

Yes, Waqar, the -- during -- there's several factors, as Mark mentioned, including seasonality in Canada. The number of rigs that we actually ran during 2006, so a rig that had revenue during the year, was 331. When you look at the summer timeframe, Canada wasn't very active, quite frankly, or you would have seen a higher total rig count. And as Mark mentioned, there's always a few percent of our rigs that need a repair, we need to stop and do whatever we might need to do, and that's [inaudible] the industry. In terms of when I look at the 300 and roughly 40 rigs that can be run today, the remaining ones, there's frankly not a lot of book value there.

You might recall, we bought a lot of rigs over a lot of years, very inexpensively. And we do depreciate those assets. And so whether we do or don't activate that equipment is, I don't think, any meaningful impairment issue, or anything like that. Whether we activate them is always based on demand. I mean, we could have run-off and activated every rig in our fleet, and hired a bunch of yards to do it, and so on and so forth. But our belief is when we spend money on rigs, we want to know that we get a good return for shareholders, or at least to the best of our ability, that is what we're trying to do. So we try to make those decisions each quarter based upon the demand that's out there. So as demand improves, will we activate more rigs? Probably. But I don't see any disposal or write-off issue, which is I think what you might have been suggesting.

Okay, great. Thank you very much.

Kurt Hallead, RBC Capital Markets.

A couple of follow-ups. In terms of the rigs that you have in the market in 2007, can you give us the percentage that you will have on contract on average for the year? Is it roughly 10% of your fleet, 20%? Can you give us some general sense on that?

Currently, around 75 rigs, I believe off the top of my head, are on contract initially at terms of a year or more. As we go through the year, that will drop to somewhere between 40 and 45, weighted a little bit toward the end of the year. But relatively fairly evenly over the year they will come off contract.

Okay. And then I had a couple things, wasn't quite sure if I heard correctly. On the outlook for rig activity, you mentioned the number 255 in the first quarter. Was that total North America for you, or was that just the U.S?

That was total North America. That's about in line with what we've been running.

And the 255. You ran 257 -- 267 in January. 250 in the U.S, 16 in Canada.

It was -- the drop in January was the big drop into early February. That's stabilized in recent weeks.

Okay, so like can you just give me just a general expectation of what you're thinking for Canada in the first quarter alone?

Canadian activity has been pretty weak. I mean, off the top of my head, we've bounced around between 12 and 16 rigs this quarter. Which is, I would tell you from a supply point of view, probably a good thing. [inaudible] looking down the road. I don't recall any time period prior to this year the Canadian rigs we haven't run pretty much full out first quarter, starting somewhere mid December or earlier, and continuing until mid March. And that has not been the case this year.

Got it. Okay. So, and the other thing I wanted to clarify with you was on drilling fluids. I wasn't sure if I heard you correctly. Did you say $35 million to $40 million per quarter in revenue for '07?

Yes, that work kind of comes as it comes. It's clearly a guess, but I would tell you that 2006, we did have some real big jobs that were great opportunities that enhanced our revenue. Those may occur again. But internally at least, we don't tend to expect them. They are just further opportunities, and that's where that number comes from.

Okay. And if it's any solace to you, back in 2001, your stock stopped going down once rig activity started rolling over. So you may draw some solace in that with the fact that activity is coming down. And we'll see if the market thinks that your stock is at a low. So in any event, that's the follow-up I had for now. Thanks a lot.

Mike Drickamer, Morgan Keegan.

Well, guys, I think everything has been just about asked and answered at this point. Let me slip in one more here. If you look at the rigs that the have been idled, what kind of characteristics are you seeing in that fleet of idled rigs? Is it primarily your smaller lower horsepower rigs? Or larger ones? Or what are you seeing in the rigs that are being idled?

What we have seen is very typical of what happens in a downturn, and it's no different than I've experienced in my entire career. The first thing that slows down is your smaller rigs. And then the second thing that slows down is your larger horsepower rigs. And that's where we've seen most of the slowdown. About half under 750 horsepower, and about half greater than 750 horsepower. And a lot of those are in the 1,500 to 2,000 horsepower range. Pretty typical.

All right. John, so if I look at the revenue mix then for those, with half being less than 750 and half greater than 750, the revenue mix for those would probably be pretty close to what your average has been. Correct?

I would think so, yes.

Yes, so there wouldn't be a lot of mix impact from those rigs being idled then on the average daily revenues?

I agree with that.

I would too.

All right. Thanks, guys. That's it for me.

Kevin Wenck, Polynous Capital Management.

John, listening to your comments on costs, and then listening to overall comments on rig activity and so forth, and then hearing the '07 CapEx budget, it looks like by year-end '07, you could draw into the line of credit again by probably $200 million to $250 million. Does that look like a reasonable assumption?

I don't think so. I think that we've repaid the line of credit since year-end. And based on our comments, I would not see us being drawn on the line at year-end based on those numbers. That's obviously back of the envelope on my part. But the only thing I can think of that you might be ignoring, is that if you have less rigs running, what ends up happening is a lot of cash shows up from your receivables versus payables relationship.

Yes, I have receivables dropping close to $100 million.

All I can suggest is you look at history at different levels of activity, and you might find that your answer -- my guess may be wrong also. But I think you probably generate more out of receivables, net payables than you're thinking.

Okay. Thanks for your help.

[Kathy Bernstein, KBV Capital].

Yes, I have a question in a different vein. I was looking at embezzlement costs, and they were negative. Do you expect any recovery?

And they were negative? In terms of recovery, we don't know. At the point we feel confident that we would have a recovery, we would record it. The court continues to go through its work, and hopefully that will resolve itself over the next few months or couple of quarters. But at this point, we don't have any clear indication what recovery we would get or how much it would be. So we have not recorded anything.

Thank you.

There are no further questions at this time. I'd now like to turn the call back over for closing remarks.

I'd like to thank everybody for their participation, and look forward to speaking with you at the end of next quarter. Thank you very much.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Have a good day.