Patterson-UTI Energy Inc (PTEN) 2008 Q3 法說會逐字稿

Good day ladies and gentlemen and welcome to the third-quarter 2008 Patterson-UTI Energy Inc. earnings conference call. My name is to Tawanda and I will be your coordinator for today.

At this time all participants are in listen-only mode. We will facilitate a question-and-answer session towards the end of this conference. (Operator Instructions). As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to Mr. Geoff Lloyd on behalf of Patterson-UTI Energy. Sir, you may proceed.

Thank you, good morning. On behalf of Patterson-UTI Energy I'd like to welcome everyone to today's conference call to discuss the results of the three and nine months ended September 30, 2008. Participating in today's call will be Mark Siegel, Chairman; Doug Wall, Chief Executive Officer; and John Vollmer, Chief Financial Officer.

Again, just a quick reminder that statements made in this conference call which state the Company's or management's intentions, beliefs, expectations or predictions for the future are forward-looking statements. It's important to note that actual results could differ materially from those discussed in 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 the demand for Company services and their associated effect on day rates, rig utilization and planned capital expenditures, excess availability of land drilling rigs including as a result of the reactivation or construction of new 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 these 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 or through the SEC's EDGAR system. Again the Company undertakes no obligation to publicly update or revise any forward-looking statements. Now it is my pleasure to turn the call over to Mark Siegel for some opening remarks to be followed by questions and answers. Mark?

Thank you Jeff. Welcome to Patterson-UTI's conference call for the third quarter of 2008. I wish you all a good morning and thank you for joining us today. I trust 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.

I plan to begin by taking a couple of minutes to review briefly the financial results for the just completed quarter. I will then turn the call over to the Doug Wall, Patterson-UTI's President and CEO, for some comments and color on our operating results. After Doug's comments on the quarter, I will make a few comments on the market outlook even though we have very little clarity at the present time. As always, we will be pleased to take your questions following these prepared remarks.

Today we reported net income of $109 million or $0.70 per share for the three months ended September 30, 2008 compared to net income of $98.2 million or $0.62 per share for the three months ended September 30, 2007. This represents an 11% improvement year-over-year.

Revenues for the third quarter of 2008 were $609 million compared to revenues of $524 million for the third quarter of 2007, a 16% improvement. For the nine months ended September 30, we reported net income of $268 million or $1.72 per share. This compares to net income of $354 million or $2.24 per share for the nine months ended September 30, 2007. Revenues for the first nine months of 2008 were $1.64 billion compared to revenues of $1.59 billion for the first nine months of 2007.

Once again, I wish to remind you that the results for the nine months ended September 30, 2007 include pretax nonrecurring gains of $59.6 million resulting from the sale of certain E&P assets and the recovery of embezzled funds. These gains net of taxes increased net income for the nine months ended September 30, 2007 by $38.7 million or $0.25 per share.

During the quarter we repurchased two million shares of the Company's stock for an aggregate purchase price of $50 million. Although the current price for the Company's stock is well below the level at which we purchase shares, we believed and continue to believe that at an approximate price of $25 per share we were obtaining a good value for the Company.

This price reflects a decline of 33% from the price of the Company's recent high. The Company still has authorization to repurchase to further $129 million worth of stock under our most recent authorization from the Board.

And finally today I'm also pleased to report that our Board declared a quarterly cash dividend on our common stock of $0.16 per share to be paid on December 30, 2008 to holders of record as of December 12, 2008. Based on our closing price on October 29, of $12.32, our stock has a current yield of 5.2% which we believe to be among the highest yields achievable in the energy services sector. I would now like to turn the call over to Doug Wall for a discussion of our operating results for the quarter.

Thank you Mark. I would like to make a few brief comments on the operating division starting with the drilling company. For the quarter ended September 30, 2008 the Company had an average of 276 drilling rigs operating, up 32 rigs from Q2. The rig count for the quarter averaged 264 rigs in the US and 12 rigs in Canada.

By comparison, a year ago we averaged 234 in the US and nine in Canada. Our drilling activity accelerated nicely throughout the quarter. On average, 269 rigs operated in July, the count jumped to 278 in August and further increased to 281 rigs working in the month of September.

For the first three weeks of October, this growth continued this upward trend and only in the latter stages of the month have we seen any small drop-off in the rig count. We were very pleased by the expansion in US rig count of some 40 rigs this year, further testament to our belief that our rigs are quite capable of providing valuable services for our customers as well as operating efficiently and safely.

In fact, we expect we would have seen even further growth in the number of rigs if not for the precipitous decline in commodity prices and the recent collapse of credit markets. Overall, our drilling business had an excellent quarter.

As was expected, our Canadian utilization improved during the quarter coming off the seasonal lows during Q2. We averaged 12 rigs working in Canada for the quarter and anticipate we will stay in this range throughout the remainder of the year. We have geared up for a very busy winter drilling season in Canada.

Overall, average revenues per operating day during the third quarter were $19,620 compared to $18,740 in the second quarter, a very nice improvement of $880 per day. Average direct operating costs were $11,130 for the third quarter, down $170 per day from the $11,300 we experienced in Q2.

Overall, our gross margins improved by $1,050 per day from Q2. At the end of the quarter, we had 54 rigs working under term contracts which had an original term of one year or more. At the present time, we have 25 additional term contracts for new build rigs that will be activated over the next five quarters.

Let me talk about a few of the operational highlights for the quarter. We introduced five new rigs to the marketplace during the third quarter, three of which were our new (technical difficulty) 1500 rigs. Two of these rigs were deployed in the Barnett Shale and the other in the Haynesville shale.

We also introduced another of our highly successful walking rigs in the Rockies. This brings our total fleet of walking rigs to 12 rigs with another 10 to be deployed over the next five quarters. In total, through the third quarter of this year we have introduced 11 new rigs to the marketplace, all of which are operating very efficiently and at very attractive rates and margins.

I should point out that we have now branded our new advanced technology rigs the apex series. From this point on, you will hear us refer to all of our new advanced technology rigs as apex rigs. For example the new 1500 horsepower rigs we have been introducing throughout this year which we have formally referred to as IDEAL rigs will now be known as apex 1500's.

Our newly designed advanced technology rigs that were specifically designed for small locations such as we find in the Appalachians, these rigs will be known as apex 1000's. And finally all of our highly acclaimed walking rigs will now be known as apex walking rigs.

We anticipate completing an additional six rigs in Q4, four of which will be the apex 1500's, the other two will be apex walking rigs. All of these rigs will be deployed in either of the Barnett Shale, the Haynesville Shale of East Texas and North Louisiana or the resource plays in the Rockies.

Over the next two years we now expect to construct 34 new advanced technology rigs. Of these, 24 have been contracted on three year terms and one on a two-year term, all of these with very favorable pricing.

With our industry-leading apex walking rigs and all of the new builds for both 2008 and 2009, we will exit 2009 with approximately 60 new state-of-the-art apex drilling rigs. In addition, we have also a substantial number of rigs that have been totally refurbished over the last three years. We expect that the addition of these new rigs together with the refurbished rigs will certainly help to mitigate the impact on Patterson-UTI of the decline in overall rig activity and margins we may see in the coming months.

Let me turn now and make a few comments about our pressure pumping business, Universal Well Services. As expected, business levels in the pressure pumping business in Appalachia improved during the quarter.

Revenues for the third quarter of 2008 reached an all-time high of $60.6 million, up over 6% sequentially and 4% higher than the same quarter a year ago. The number of jobs completed improved by 9% sequentially but it is down 8% from the record number of jobs we completed in the same quarter a year ago.

Average revenue per job declined somewhat on a sequential basis to $16,240 reflecting a slight change in our job mix. We certainly did more cement jobs and slightly fewer frac and nitrogen jobs.

Activity levels have not been as high as we originally anticipated in this market primarily due to delays in permit approvals for use of land and water resources. We do however, believe that these are delays and do not reflect any less enthusiasm for the long-term development of the Marcellus and Huron Shale plays.

Operating margins in this division are still being impacted by high fuel and sand costs as well as additional labor costs as we geared up for the expected increase in business driven by activity in the Marcellus Shale. In terms of capital, we spent $18 million on new pressure pumping equipment during the quarter with a large amount of that directed towards upgrading our fracturing capabilities.

We've now taken delivery of five of our new 2250 horsepower quintuplex pumps that were specifically purchased for horizontal fracs in the Marcellus. We will have five more of these units delivered prior to the end of Q4. We expect all of this additional equipment this year to drive significant growth.

Turning now to the drilling fluid segment, as you might have expected, Ambar Lone Star was significantly impacted by both Hurricanes Gustav and Ike. Revenues were down over 8% sequentially as our operations were suspended for over 20 days at most of our Gulf Coast facilities. Our facilities at Cameron, Intercoastal City and Galveston all experienced damage.

However, I am pleased to say we're now back up and running. Margins in this business continue to be very thin as cost increases in [barrite], fuel, raw materials as well as labor costs continue to put pressure on our margins. We do not see any meaningful change in this business in the immediate future.

With that, I'll now turn the call back to Mark for some concluding remarks.

Thanks Doug. As Doug's comments reflect, we saw a major step change in our drilling business in the third quarter with accelerating demand for both new and existing rigs. As we had discussed in prior conference calls, we had expected this change based on strong commodity prices and in particular natural gas prices at $8 or higher.

What a difference I've seen in the last 30 days or so. I'm not sure I have ever witnessed such a dramatic change in the business climate in such a short period of time.

The combination of falling commodity prices and the general turmoil in the credit markets coupled with uncertainty surrounding the US election have given rise to an unprecedented decline, not only in the stock and capital markets but also in consumer confidence.

Personally, it's like a plane hitting an air pocket. You keep waiting for the plane to reach a level altitude at which smooth flying resumes.

Although we don't really have a lot of clarity as to where all of this is headed, several things are becoming more clear. Assuming that commodity prices stay at depressed levels and credit markets are constrained, our customers certainly are going to have less free cash flow in 2009 as well as less access to capital.

This is bound to have an impact on rig count in both the US and Canada. Right now, it seems impossible to assess the likely magnitude of the decline or its expected length.

As we said in our press release, we expect that our rig count will be 283 for October, up two from September. We believe, however, that based on a reduction of activity by reason of the holiday season and based on input from our customers that our total rig count for the fourth quarter will be in the low 270s including approximately 12 rigs running in Canada. We expect that margins during the fourth quarter will remain flat at approximately $8500 per day.

Having said all this, it must be pointed out that natural gas prices in the 6 to $7 range are not that bad. In fact, those prices are very similar to the prices we had one year ago. We do know that at these prices, approximately 1700 rigs were working in the US a year ago.

Will it get worse than this? We really don't know. But we must keep things in perspective.

We believe that any major decline we see in drilling activity will result in a pretty quick decline in the supply side of natural gas. Subject to what happens on the demand side, we believe that any major decline in production will likely result in lower supplies and a resulting increase in prices thus ultimately driving more drilling activity. We refer to this as the virtuous cycle.

Although it may take some time for the world's economies to recover from this crisis, we do believe that in the long-term we will continue to have to drill more wells to meet the demands of consumers and the economy in general. Moreover, we believe that the high depletion rates of current gas wells will inevitably mean that a decrease in drilling will quickly lead to a substantial decrease in supply.

Indeed, our recent experience with commodity cycles albeit without the sturm und drang of the current crisis, are shorter and less steep due we believe to this acceleration in depletion rates. As a Company, we're taking steps to prepare for a decline in the rig count whether modest or sharp. We're taking a hard look at our cost structure and we will reevaluate our discretionary capital expenditure program.

We believe, however, that our debt free balance sheet puts us in an enviable position to increase shareholder value during this downturn. That said, it won't be painless but we are better positioned than ever to respond to these difficult times.

Before concluding, I would like to take a moment to address our stock price. Like so many investors, I'm frustrated at the valuation accorded to our Company. I had expected that with our balance sheet with no long-term debt, net plant property and equipment of more than $1.9 billion and current assets of more than $600 million together with our yearly annualized dividend of $0.64 per share was sure that our stock price would not fall to the current level. Of course, like others, I am surprised by the depth of the economic crisis we currently find our country.

Before we open the call to questions, we would like to take this opportunity to express our sincere appreciation to the employees of Patterson-UTI. We have survived and thrived during tough times before and it is the dedication and resolve of our people that will help us to continue to succeed. We will now open the call for questions.

(Operator Instructions) John Fitzgerald, Raymond James.

On the drilling side I guess costs were actually down during the quarter. Maybe some help from lower fuel costs and I don't know if you were still deploying some of your stacked rigs. But could you guys describe how you are able to control costs so well and where you see that going over maybe the next quarter or two?

In the second quarter, we expended quite a few dollars activating rigs. As Doug mentioned earlier, our US rig count during the first nine months was 40 higher than it was at year-end.

As we went into third quarter, it was a little bit unclear to us whether we would get savings in the third quarter or if it would occur in the fourth. But most of the reactivation costs did occur during the second quarter resulting in an improvement in our average costs per day.

We also had in response to some other drilling companies, we increased wages for rig employees late in the third quarter. So that actually contributed somewhere toward $100 in increased costs. So without that, we would've been closer to $11,000 or so in costs per day in the third quarter.

Looking forward to the fourth quarter, we will see the rest of that increase which is approximately $500 a day, and that would take our per day costs in Q4 to about $11,500. And also since those costs are a direct pass-through to the customers, we will get a little bit of benefit in the average revenue per day side and we would guess that that would be somewhere around $20,000 in Q4.

Thanks for the color. And then I guess bigger picture, you guys have a clean balance sheet. We're thinking next year might be a good chance for consolidation in the market. Is that a possibility for you guys? Are you still inclined to stick with a new build and put out your apex rigs or are you still just taking maybe you could just go on the refurb side ex what you've already planned on putting out in the market?

Our view about this is that we continue to look at all possible transactions that are presented to us. From our perspective, you have to consider the quality of the assets that you can obtain in every given transaction as against the price.

Over the last few years we've thought that the best things we could put our capital into was the refurbishing of our existing rigs, our new rigs and our stock buyback and our dividend and that is in fact what we have done. We're very proud of that record. We think that was the good way to deploy capital, a smart allocation of resources. But we will continue to look at transactions and to the extent to which that makes sense, we will consider them.

Jeff Tillery, Pickering.

Recognizing that there is a lot in flux right now in '09 capital expenditure plans will certainly move around a bit, could you walk us through how you think about maintenance capital and then what is committed for 2009 for the new build program already?

Let me respond to that in the following way and turn it over to John for a little bit of color. We have had a long-term program as you know of refurbishing rigs of -- when customers sought specific fit for purpose rigs, building fit for purpose new rigs -- those are our walking rigs. We've also had these apex 1500 rigs which we formally called IDEAL rigs which we bought in 2006 and have been putting out into the market this year.

So we have had a long-term program of building new rigs when customer demand required it and to meet specific needs of our customers. We have continued that program and expect to continue that program into 2009.

That said, in previous conversations with -- previous conference calls, we've indicated that we expected our CapEx budget next year to be approximately $600 million. That being said, that was before we had our annual budget cycle. We're in the process of our annual budget cycle right now. We will do as a Company operating as well as capital budgets.

Those will be presented to our Board later on for the Board's review and approval and we may increase or decrease that $600 million going forward depending on what we see. With that and obviously as I said in my prepared remarks, we will be taking a hard look at discretionary capital. With that, I will turn it over to John for the maintenance capital comments.

For maintenance capital we have actually experienced decreasing costs per day. But historically we have used about $1000 per operating day for maintenance capital. Of late it's been a little lower than that.

On that basis, I would think maintenance capital for next year would be somewhere towards $80 million. And as we finalize our budget, if we continue the expansion of the pressure pumping business, I would guess somewhere toward $50 million related to that and the other businesses. And with a not yet completed budget but guess of capital next year around $600 million, that would leave $470 million for new rigs and upgrades of other equipment.

Thank you for that. I just want to make sure I have the numbers clear on the incremental new builds versus what you guys talked about on the second quarter conference call. How many of the 34 were incremental versus last time you guys talked about it?

Jeff, that number is probably eight. You know, the 34 that we talked about is really from this point forward which includes about six of the previously announced 1500 horsepower rigs that we had announced a couple of years ago. So the real number that I guess over what we told you last quarter was eight rigs.

My last question, from a strategic standpoint -- I guess it was kind of fall of '06 we started going through this plateauing in rig count as well. You guys were disappointed and willing to take rigs off the market to try to preserve industry pricing. Should we think about that the same way this time around as rig count falls? At least to a point you guys are more willing to sacrifice utilization at price. Is that the right way to think about it?

I think what we have done historically is make a pretty much case-by-case, rig-by-rig evaluation of each opportunity to proceed and made a decision kind of on a basis -- we try to make them rig-by-rig as to whether it's appropriate to take, maintain the rig operating potentially at a slightly lower price or to in effect lay the rig down to in effect try to help maintain price. That's a decision we make case-by-case. I think it's fair to say that we are going to try to do both maintain share and maintain price.

[Ben Dale], Bernstein.

I had just some questions on where the activity was weakening the most. Could you give us some color on which regions you're seeing the greatest weakness in, how big of a quality spread you're seeing between high-end rigs and low-end rigs? And which particular operators? Are you seeing the large cap E&P's or the privates and microcaps falling away from this market the most?

Well to start off with, interestingly enough as we said the rig count actually went up in the month of October and it's only really been the last couple weeks that we have seen any sign of weakness at all and it's been very spotty. I would hesitate to try and generalize at this point about where it is, what size of rigs.

I would say at this point that from what we've seen, which I don't think is the same as what some of our competitors have seen, we have seen some weakness in East Texas, and we have seen a little bit of weakness in West Texas. I think the East Texas piece of it surprised us a little bit because primarily that's the area where the Haynesville is driving a lot of business.

In terms of rigs sizes it's been really highly unusual. You might have expected that smaller rigs, less capable rigs might be the ones being laid down. To date that is not what we have seen. In our own experience, we have seen some very good quality rigs that people are just saying look, I can't continue my program. I'm going to have to let that rig go.

But I think it's a little too early in the process to really generalize about the type of rigs and some of the markets. To be honest with you, we would have probably expected some different markets to show signs of that weakness first and so far those markets have hold up very, very well.

Great, and just on the other side of the equation, obviously steel costs have come down. Construction costs appear to be starting to moderate. Have you seen any signs that the cost of refurbs on new builds in the rig market are starting to moderate? And if so, by how much? Or when would you expect to see that if it hasn't already started?

Well we have seen steel prices recently sort of dropping in the 15 to 20% range. So I think we have seen some of that already. I think they will continue drop.

I don't think it has a huge impact on the costs of new build rigs. But it probably could be somewhere in the order of magnitude of $1 million on some of these rigs all in. But I don't think it's all washed through the system at this point.

And I would just add one further thought. So far in terms of what is being experienced with respect to some customers deciding to curtail their rig programs, I think it's very customer specific. And we have seen as we hope we have indicated both in the press release and in our conference call so far that our rig count stayed very strong and was in fact advancing through most of October.

And we think that may be different from some of our competitors who may have seen some softness in the count earlier than that related to who their customers are. That's what we are seeing now. Frankly, we think that we may be slightly advantaged going forward as against some of our customers because of our wider ranging customer base and what some people have referred to as the checkbook customers and we have perhaps greater representation of those people for whom credit may be less of an issue.

Arun Jayaram, Credit Suisse.

Real quickly, have you seen any impacts to pricing? You mentioned that you have seen some rigs getting let go in East Texas and West Texas. What are you seeing in terms of pricing?

To be honest with you because the rig count continued to go up in October, we have actually seen our pricing continue to go up somewhat through the month of October. And having said that, we are getting some pressure from certain customers as Mark indicated before that are trying to get ahead of the game and saying hey look, I can't drill those wells at that price anymore. Can you help?

But we really haven't seen any steep discounting to this point. And again it's a case-by-case base talking to each individual customer about their needs for the next quarter and the rigs that they're going to need.

Fair enough. Second question, Mark, doesn't seem like you're getting much credit for the dividend policy. If I look to some of your peers on the offshore drilling space, Diamond Offshore has a pretty interesting policy where they pay out a dividend based on somewhat of a formula and tend to get a lot of credit in the marketplace by being a pretty significant dividend payor.

Have you thought about looking at a philosophy or strategy that focuses on returning a significant amount of your free cash flow through a dividend policy given the ying and gang and just the difficulty and short cycle nature of the North American (inaudible) business? Interested in your thoughts on that.

Yes, have given that some thought and continue to think about it. I feel that what we have done historically where we have invested substantial amounts of capital in our equipment and new rigs and upgrading our rig fleet and our pressure pumping business as well as substantial dollars spent buying back stock and then kind of the remaining in effect free cash flow going to dividend has been a pretty good policy for generating shareholder return long-term.

You know, right now I agree with you 100% that the market isn't giving us much respect for the dividend. But my thought is that right now is sort of a poor time to make judgments about kind of stock prices. My own sense right this minute is that there is a lot of dislocations in the equity markets and you're seeing a number of securities including ours I think which are wildly mispriced.

My hope is that as the message gets through to shareholders and investors that Patterson is a good strong company with a great balance sheet, no real significant exposure to the current credit issues that are sort of swamping some other places, that in effect over time people will get the message. You know the old Buffett comment about that short-term, the market's a popularity contest and long-term it's a weighing mechanism. I have a sort of comfort that long-term the weighing mechanism trumps the popularity contest.

Fair enough. Last question is obviously you have -- follow-up to Jeff's question is you have added about eight additional rigs in terms of the new build count. Are those -- have you ordered the parts for those or could those be adjusted given the changing market landscape?

Well we have placed the orders with National Oilwell for those rigs. I should point out (inaudible) that they're scheduled for delivery from National late in the third and fourth quarter of 2009. At the moment, we are in line, we have placed the orders.

We hope that by that time, this market will have corrected itself and this is part of a long-term strategy for us in terms of upgrading the quality of our fleet. We're very pleased with what we have done in the last couple of years and we think this is just a continuation of that.

Mike Drickamer, Morgan Keegan.

I wanted to follow up on earlier question where you're talking about your customer base. Can you perhaps characterize how your customer base is, perhaps what percent is the checkbook customers you referred to versus how much are perhaps larger independents that have more access to capital?

I would say about 50% of our customer base is kind of the checkbook driller. And a good chunk of our business would be what I'm going to call kind of the major independents. If there's one area or segment of our customer base that we don't do a lot of work for it tends to be the majors, the Shells, the Exxon Mobiles, the Conoco Phillips, that (inaudible) of customer.

So we have a very strong representation throughout the customer base but I would say that the majority of it is with the people like Devon's, and the EXCO's and the XTO's. And certainly we mentioned the checkbook drillers before. That is a big part of our business.

Mark, a question for you. Given the liquidity concerns in the market, I know you guys don't have any debt and you have cash. But how much of a priority is stock buybacks here for you?

You know, that is a question that as a Board and as management we wrestle with which is there is a lot of competing good uses of capital. We think that rigs that we have been building have situated the Company in a very favorable position. We also think that the buyback -- it's obviously particularly at these prices is extremely attractive.

So those are the things which are the priorities. We also think that paying and maintaining our dividend is another priority. So these are the things that in effect management is focused on.

To say which one is a higher priority or to give you a specific dollar amount, I really can't say anything more than we have $129 million authorized on the stock buyback that is not yet spent. And we have been consistent purchasers of stock when we think think the opportunities are attractive.

Dan Boyd, Goldman Sachs.

Of the eight new builds that you ordered this quarter, were any of those backed by customer contracts?

No, they were not.

So I am assuming you ordered them because you're seeing still demand for those types of rigs from customers that are willing to sign contracts?

Well, we believe that given the delivery schedules, you know those delivery schedules got pushed out into the latter part of 2009 and we felt with those delivery schedules that we needed to be in line to continue on with our program.

I should point out that a couple of years ago, Dan, we ordered 15 rigs and virtually had no commitments for them at that time. So having an additional eight rigs with no commitments presently, we're not uncomfortable with that.

Okay and then going back to the rate versus utilization question, given that you did just spend some CapEx on reactivating a number of rigs, do you think you might favor utilization a little more than you did in the late part of 2007?

No, I really -- like I said, to respond to what Mark said before, we look at each case on a case-by-case basis and decide -- both of those things, market share and price, are very important to us. But we have never been a company that is strictly out trying to get market share.

We're in business to make money and you don't pay us for how much market share we have. You pay us for the results and we have to make that balance between price and share everyday and figure out what is best for our shareholders.

Okay, understood. Of the rigs that you're seeing the customers are releasing, are any of those in the 1500 horsepower category? I would assume yes given that they are in the sort of East Texas area?

Very few of ours but you're asking specifically about us or what we're (multiple speakers)

Just what you're seeing in the industry as well.

Well we've actually been a little surprised. We have seen some competitors 1500 horsepower rigs come down in certain markets. We have had a couple of ours announce that they will be finished at the end of the current well. But in one of those cases we have already got another well for that rig to drill.

One last question. I think you mentioned that you felt like the checkbook E&P companies had better access to capital. Did I hear that correctly that they weren't being impacted by the credit crunch?

Yes, basically they drill from cash.

I think we just heard some of the guys at least on the (multiple speakers)

Let me say this to you also. I think there's two elements to that. One is that A, they in effect putting back their cash flow into the ground and that is the way most of those customers kind of think about their business. In effect for every $1 I take out, I will put back $1 or $0.80 or whatever the number is. But they're putting back in effect their royalty checks back into the ground and further drilling. So that is the first point.

Second and this is a point that I think is perhaps not maybe as well appreciated, smaller regional banks particularly banks in West Texas and other places that are very much energy-related with strong depositor basis are in the position to make loans to their customers and are doing so. That is very different from commercial money center banks which are finding themselves in a very different situation. And I think that the press is about the commercial money center banks, not these smaller local banks in certain markets if that makes some sense.

Yes it does. I guess the proper way to think about it then is your customer base may see a little bit longer of a delay if commodity prices stay low than some of the larger in E&P companies that are having credit issues that impacts them today. If commodity prices rebound, your customers shouldn't see the same downside that others are seeing, I guess is the --

Well I think that the commodity price affects all customers. The credit issues may affect some customers is what I think I'm trying to say.

Andrew Coleman, UBS.

Anyway, I had really three questions and first is kind of looking a bit more at rig substitution. We've heard some operators talk about using lower horsepower, so called sputter rigs in Appalachia or in parts of East Texas and perhaps the Fayetteville to try to save rig costs. Are you seeing that across -- or playing a bigger role in any of your other business areas?

No, we really have not seen that. I know there has been a little bit of that going on. I think some of that was primarily because they couldn't get 1000 or 1500 horsepower rigs. But I really don't think it saves much money.

The other interesting thing is that rig costs today are a pretty small proportion of the total cost of getting a well drilled and completed. In fact we have seen some numbers recently that the cost of casing is actually more than the cost of the actual drilling rig cost. So to answer your question we have not seen much of that impact of small rigs coming in and doing spudding work ahead of us.

Okay thank you. Second question just looking at your pressure pumping business, do you think that as companies drill less here in the short-term that you would expect to see or are seeing much of an increase in the amount of I guess work overwork or refrac activity as people go back and try to restimulate and keep some of these newer horizontal wells flowing?

I think there has been very few of the horizontal wells frac'd and completed up there at this point. But I think it is interesting, that market up there has always been a market where there's a lot of refracs, there's a lot of ongoing recompletion work and that is the kind of work that I think actually has slowed down over the last 12 months because people were so focused on the Marcellus and Huron.

We're now starting to see some of that traditional work come back into the marketplace because of the slowdown in some of the Marcellus and Huron. I should say that we plan on doing our first horizontal fracs in the Marcellus here in the month of November and up to this point we have not done one of those. But I said earlier very few of the horizontal fracs have really been completed to this point.

Okay, excellent. My last question is a bit more -- rolling back the clock a few more years. Looking at what happened in the 2001 2002 kind of recession here in the US which US I don't think we are necessarily in a recession right now but we will let the economists debate that. But rig count came back about 40% and of course it snapped back within really a year and a half I think largely as a result of the fact that production growth was declining in the US.

How do you think things will kind of roll forward given that production on the macrolevel is growing at somewhere between probably 2% and 8% depending on which dataset you use? Does that offset some of the (technical difficulty) discussing 35% first-year decline rate as being kind of that equalizing factor and put additional pressure on the overall drilling business?

Well I think you have asked the $64,000 question which I think a lot of people would love to know the answer for. I'm kind of reluctant to be someone who tries to answer a question I think that is fundamentally unanswerable because I don't think anybody really knows. But I guess a half a few observations that I'd like to put on the table.

First is that the notion that because there has been a production increase over the past say 12 months -- and I'm not looking at a chart, so I don't have it front of me exactly what that period has been -- but there has been a period of increase. The fact that that occurred doesn't necessarily mean that it will continue and that it's predictably going to happen again in future years.

It may well be that that increase came about owing to changes in technology for these horizontal drills in these shale plays with the stimulation and greater ability to draw the hydrocarbons out of the well, all of which may or may not be continuously improvable such that you will get continuous increases. So that is the first point.

I mean the point being that the presumption that the increase will be sustainable and will happen year-over-year strikes me as one of those questions that I don't know that there's a lot of basis for that assumption. Second, we do know that the decline rates in these newer wells particularly in the shale plays are very high and so it would seem to figure that if in fact drilling does decline in these areas for all the reasons we've been discussing that there will be a significant fall-off in production.

Third, what we don't know is the effect and severity of a decline in overall economic activity on demand for gas. But we do know that gas is principally used for heating and for electricity and only to a smaller and much lesser extent for production of goods and services, so-called industrial uses.

Given that fact and I think the numbers are something on the order of three parts home, heating and so on and so forth and one part in effect industrial; it would seem to figure that even if there is a slowdown in overall economic activity that it would not significantly impact gas usage and gas demand, all of which is to say that we are pretty optimistic that if there is a slowdown in drilling that it will not be a prolonged one.

Okay, great. I appreciate your feedback on those.

[John Daniel, Simmons & Company].

I just want to touch on customers real quick. Recognizing that a bunch of your customers drill out of cash flow, have you encountered any payment issues yet with the customers and have you made any or been requested to make any changes on credit terms to customers?

No, we haven't. In fact we watch our receivables very, very closely. In fact they actually improved by a day or so over the last quarter. All of our salespeople watch the receivables. We're talking to our customers. We have a very thorough credit check policy. We have not to this point seen any change in the behavior of our customer base.

(Operator Instructions) Todd Garman, Peters & Co.

I just want to come back to the 1500 horsepower rigs here for a second. Is it your understanding that the 1500 horsepower rigs are being released because operators no longer have wells for them to drill or is it because the rigs are being replaced with newer rigs that are coming under contract or that are signed to term contracts?

I think it's likely the former and it's very customer specific. But we believe it's just because they've run out of wells to drill with that rig in that particular area and aren't prepared to move it to a different area.

And is the fact that they might have run out of inventory in those areas, is it due to any permitting issues or is it due to some sort of constraints somewhere along the line whether they can't get (technical difficulty) or is it just simply that they don't have money to drill them anymore?

I think it's reduced CapEx or reduced cash flows from those particular fields. It has been very field specific to this point and I think there's certainly a commodity price issue at play here. There may be some fields that with $6 and $7 gas, people are not prepared to spend their cash there.

John (inaudible), Bennet Management.

I had to jump off at one point. I'm just wondering if you have kind of given a target for what your CapEx will be in '08 and how it would be spread out over the year? I know it is an uncertain time but can you talk about guidance on CapEx?

I assume you're meaning for 2009?

Yes.

We have said that -- in prior calls we had said that we expected approximately $600 million and we have kind of tried to break that down to approximately $80 million of maintenance CapEx for the drilling business, approximately $50 million for the pressure pumping business and the balance for our refurbishment program and our new rigs.

Having said all that, that has been put forward in prior conference calls and we're just repeating it today as being what we have said. We also said -- we have covered this. I'm being a little quick about this. We also said that we're in the process of our yearly budget cycle where we do both operating and capital budgets, that that would be presented to the Board later in the year (technical difficulty) finally approved.

Obviously in light of the current circumstances, we're taking a very hard look at discretionary capital and trying to make a careful judgment as to whether that $600 million ought to be adjusted. And as we go forward, we expect to be asked that question at the beginning of next year on our conference call and kind of give you an update at that time.

At this time there no further questions in queue. I'd now like to turn the call back over to management for any closing remarks.

Thank you. We would like to make a couple of just comments and I'll turn it over to John Vollmer about some very specific points to perhaps help people in their thinking about our business. John?

A couple of items we didn't cover on the call -- our estimate for the tax rate in the fourth quarter would be an effective rate of about 35.8%. The rate was slightly lower in the third quarter. We got a little bit of benefit from (inaudible) to our prior year tax return when we filed it.

Another in terms of pressure pumping business, activity continues to be strong in our Appalachian pressure pumping business. But I would like to remind people that in the fourth quarter we do see typically a seasonal decline as a result of less daylight hours and less workdays due to the way Appalachia specifically deals with the Thanksgiving holiday and the Christmas holiday. SO our guess is that sequentially we have seasonal decline of about 5% revenue versus the third quarter.

However we think the margins will stay very similar on a percentage basis at somewhere around 40%. The fluids business is a little bit difficult to understand in the third quarter of given the impact of the hurricane. And our guess there is that sequentially revenue will be off about 5% but that on a margin basis it will become a little bit more (technical difficulty) quarter at somewhere in the 12 to 13% range. Included in the third quarter numbers for fluids was the $650,000 charge related to damage that occurred to our facilities.

Lastly on the E&P segment we benefited like other E&P companies from great commodity prices earlier this year. With the decline of those prices, we would expect that our -- we will be down probably 20% somewhere in the $11 million or so range in revenue but that our cost of that revenue will drop back down toward somewhere in the 25% range. And that was it.

Thanks John. I would like to thank all of the participants in today's call for their being on our call and to look forward to our next call in February. Thanks everybody.

Thank you for joining today's conference. That concludes the presentation. You may now disconnect and have a great day.