Patterson-UTI Energy Inc (PTEN) 2008 Q4 法說會逐字稿

Good day ladies and gentlemen, and welcome to the fourth quarter 2008 Patterson-UTI Energy Incorporated earnings conference call. My name is Latrice. I will be your coordinator for today's conference.

At this time all participants will be in a listen only mode. We will conduct 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 will now turn the call over to your host for today's conference, Mr. Geoff Lloyd on behalf of Patterson-UTI Energy. Please proceed sir.

Thank you very much, and good morning to everybody. On behalf of Patterson-UTI Energy I would like to just welcome you to today's conference call to discuss the results of the three, and twelve months ended December 31, 2008. Participating in today's call will be Mark Siegel, Chairman, Douglas 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 is 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, deterioration in the global, economic environment, declines in oil and natural gas prices that could adversely affect demand for the company's services and their associated affect on day rates, regularization, and planned capital expenditures, excess availability of land drilling rigs, including result of the reactivation or construction of new land drilling rigs, adverse industry decisions, 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 or through the SEC's EDGAR system. The Company undertakes no obligation to publicly update or revise any forward-looking statements.

At this time it is my pleasure 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 welcome to Patterson-UTI's conference call for the fourth quarter of 2008.

I trust 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. Our plan this morning is to take a few minutes to review the results of the 3 and 12 months ended December 31, 2008 and to indicate some of the financial highlights from the just completed quarter, which I hasten to add was an excellent quarter in terms of financial results. I will then turn the call over to Doug Wall, Patterson-UTI's President and CEO, who will make some brief comments on the results of the individual operating results and current operations. 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 moment. As always, we will be prepared to take your questions following these prepared remarks.

To summarize, net income for the 3-month period totaled $79.5 million, or $0.52 per share compared to $85.1 million, or $0.55 per share for the three months ended December 31, 2007. Revenues for the quarter were $570 million compared to $521 million for the fourth quarter of 2007. For the 12-month period ended December 31, 2008 net income totaled $347 million, or $2.24 per share compared to net income of $439 million, or $2.79 per share for the 12 months of 2007. Revenues were $2.2 billion for the year ended December 31, 2008 compared to $2.1 billion for 2007. In summary, we had an excellent fourth quarter and an excellent 2008.

As reflected in our press release, these reported results for 2008 include three unusual non-cash items. Number one, write off of the goodwill in our fluids business of $10 million. Number two, a charge of $10.4 million related to the retirement of 22 rigs from our drilling rig fleet. And third, an impairment charge of $2.4 million related to some of our E&P properties. On an after tax basis, these three items reduced our earnings by a total of $0.12 per share for the quarter.

Capital expenditures for the quarter were $119 million and $449 million for the year. During the quarter, we repurchased 1.5 million shares of the Company at an average price of $10.64. The remaining authorization under our share repurchase program now stands at $113 million.

I would like to now turn the call over to Doug who will discuss our operations for the fourth quarter and for the current quarter.

Good morning, and thank you Mark. I will make a few comments this morning on each of the operating division's results starting with the drilling Company.

For the quarter ended December 31, 2008 the Company had an average of 252 drilling rigs operating, including 239 rigs in the US and 13 rigs in Canada. This compares to an average of 276 drilling rigs operating including 264 in the US and 12 in Canada for the third quarter. Average revenues per operating day during the fourth quarter were $20,210 compared to $19,620 in the third quarter. This primarily reflects the pass through of the $500 per day wage increase we instituted in early September, as well as improved rig pricing that was achieved in Q3 and in early Q4. It also includes a $1.2 million buy-out on a term contract on a rig in the Rockies which increased our average revenue per day for the fourth quarter by approximately $50. Average direct rig costs per operating day were $11,210 for the fourth quarter compared to $11,130 for the third quarter. Wage cost increase, that I mentioned earlier, was largely off-set by other cost reductions.

Our activity levels in the US peaked in early October with a count of 275 rigs. Since that time we have witnessed perhaps the steepest and quickest decline we have ever seen. The US average monthly rig count for the quarter was as follows. October, 270, November, 247, and December, 201. We recently announced our January US rig count averaged 147 rigs, further confirmation of the steep decline in the US market. Our current rig count stands at 132 total rigs, including 120 in the US and 12 in Canada. Low commodity prices, too much oil and natural gas supply, combined with declining demand as well as tightness of the credit markets, all of these things have forced our customers to significantly reduce almost all drilling programs. Virtually no segment of the market has remained unscathed. All our regions, all sizes of rigs have been impacted, and in most cases it appears that little consideration has been given to the performance and efficiencies of any particular rig. Customers' budget plans have been cut on mass and rigs have been idled regardless of price and performance. The US rig count would likely be even lower today were it not for long-term contracts. That said, we may have felt the initial impact of this downturn more so than some of our competitors who have had a higher proportion of their rigs under term contract.

At the end of the quarter, we had 52 rigs working under term contracts of various length. An additional seven term contracts will expire during Q1, partially off set by six new builds that will be delivered this quarter and all of them under three-year term contracts. Our 22 new builds to be delivered this 2009 will play a major role in our utilization and our earnings going forward.

A couple other drilling items of note are as follows. We delivered five new rigs to the marketplace in Q4, four of our APEX 1500's, two of each went to the Barnett and the other two went to Haynesville. We also introduced another of our APEX walking rigs in the Barnett. At the end of the year, we had 13 of our APEX 1500's in the field and a total of 14 of our APEX walking rigs. As mentioned earlier, our new-build program is expected to deliver a further 22 new APEX rigs to the market during 2009, and most importantly including ten of them to the Appalachian region.

I also want to mention that as part of our yearly budget process we reviewed our entire rig fleet. In connection with this, we decided to retire 22 rigs. These rigs had an average horsepower rating of less than 800 horsepower and an average depth-rating of less than 12,000 feet. Many components from these retired rigs will be used as spare parts for other marketed rigs.

Turning now to the pressuring pumping business, Universal Well Service. Fourth quarter revenue was up 5% over the same quarter in 2007. Revenue for the quarter was $56.9 million, and average revenue per job increased to $19,920. Even though the number of jobs declined 21% for the quarter on a year-over-year basis, the mix of jobs changed significantly. We completed our first horizontal fracs in the Marcellus Shale during the quarter and the sheer magnitude of these jobs made up for the short fall in some of our traditional business in this market. Falling commodity prices and the focus on the deeper plays such as the Marsalis and the Huron Shale plays have caused some retrenchment in our traditional business. We expect this to continue in the coming quarters, but the bright spot in this market continues to be the shale plays and we feel this segment of the market will continue to grow.

We spent $61 million on capital expenditures for this market during 2008, with a large amount of that directed towards upgrading our fracturing capabilities, where we added five Quintuplex frac pumps as well as additional triplex equipment during the year. Much of this additional horsepower came on-stream late in the year. A second complete Quintuplex frac spread should delivered and in operation within the next few months. Obviously, the major operational highlight for the quarter here was the deployment of our people and equipment on our first horizontal Marsalis fracts using in new Quintuplex pumping equipment. We completed five large horizontal fracts during the quarter showcasing our capabilities and our service quality. Universal is a market leader in the Appalachians in pumping large fract jobs, including both these horizontals and nitrogen fracts. With our new equipment, we feel we are very well positioned to service this growing market.

Turning to the drilling fluid segment, we witnessed a slight improvement in our fluids business for the quarter with revenues up almost 7% sequentially. Revenues year-over-year were up 13% but preimpairment income was actually down slightly. Lack of activity in the Gulf of Mexico is still hampering our operations, and the dramatic decline we have seen in the number of wells being drilled on land will continue to negatively impact both our revenue and our earnings. Our E&P business during the quarter saw revenues decline by over 50% as commodity prices fell dramatically. The average price received for oil was 46% of what we received in the previous quarter, and our average natural gas price received was about 58% of what we received in the previous quarter.

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

Thanks, Doug. In our last call with you at the end of October, we were just seeing the first signs of turmoil in our markets. The last 100 days or so have been unprecedented in our industry and in the world's business markets. Never before in my lifetime have we seen such a dramatic change in the business climate in such a short period of time, and never before has it impacted virtually every business segment, every industry in every country around the world. The combination of falling commodity prices and general turmoil in the credit markets have combined to slow the oil services industry to a level not seen for years. This is most unfortunate, as our industry produces natural gas and environmentally friendly fuel which is mostly US source and we employ a substantial US work force.

Although we don't have a lot of clarity as to where all of this is headed, several things are becoming clearer. Until commodity prices make a sustained upward move away from the current depressed levels, our customers will likely maintain their current posture of limiting their spending programs. Until credit flows freely, the tendency of everyone, including our customers, is to hoard cash and this will depress activity levels. All of these factors do not bode well for our business in 2009. What does bode well for our business is our fundamental strengths, the nature of the land-drilling industry and the laws of supply and demand.

These strengths include first, our strong balance sheet with $81 million in cash at year-end and now in excess of $130 million in cash and our unleveraged financial condition. In this regard, it is important for investors to keep in mind that we own outright 347 land rigs and a huge inventory of associated equipment and property along with substantial assets and pressure pumping, fluids and E&P. More over, as Doug related, these assets include some of the most technologically advanced equipment for drilling and for pressure pumping, which is ideally suited to the markets in which we work.

Second, the land drilling business is highly scalable. It can be increased in boom times and reduced in bear times and the participants are, unfortunately, well experienced in this two-way street. As a Company, we are taking steps to react to this dramatic decline in the rig count by curtailing both operating and capital costs. For 2009, we have budgeted $200 million for capital expenditures for upgrades and maintenance of our rig fleet, additional Quintuplex pumps to increase our horizontal capacity in the Marsalis and for other business units. In addition, we have budgeted $320 million for 22 new rigs that we anticipate delivering in 2009 all under long-term contracts with very good returns.

Third, we believe that any prolonged decline in drilling activity will result in a pretty quick decline in the supply of natural gas. We must remember that 72% of the natural gas used in this country is supplied by the US land business. More over, we believe that high depletion rates of current gas fuels, like the Barnett Shale, will inevitably mean that a pronounced decrease in drilling will quickly lead to a substantial decrease in supply. Subject to what happens on the demand side of the equation, we believe that any major decrease in supply will likely result in higher prices, thus ultimately driving more drilling activity, the laws of supply and demand. For this reason, we do believe that -- for this reason, we do believe that the industry cannot stay at these depressed levels for a long period of time.

The Company also declared a quarterly cash dividend on its common stock of $0.05 per share to be paid on March 31, 2009 to holders of record as of March 12, 2009. This reduced dividend reflects the current business environment for oil services. Most fundamentally, the perception that saved capital is likely to be especially valuable in building long-term shareholder value during this downturn. Additional financial flexibility is simply an advantage we want to have. We believe that our healthy balance sheet and our debt-free situation puts us in an enviable position to weather any storm. We look forward to the opportunities that are likely to arise for our Company in this difficult business environment.

Before we open the call up to questions, we would like to take this opportunity to express our sincere appreciation to the employees in each of our business units for their dedication and hard work. Our continued success is just not possible without their efforts, and we wish to recognize each and every one of them. Thank you. At this point I would like to open the call for questions.

(Operator Instructions) Our first question comes from the line of Jeff Tillery with Tudor, Pickering, Holt.

Hi, good morning.

Good morning.

Good morning.

Could you give us a feel on the existing rigs and the new builds that are contracted, what those day rates are relative to what your overall fleet average was in the fourth quarter? Is it a big premium, close to parity? I'm just trying to get a feel for what is locked in.

John, do you want to take that question?

Sure. In terms of the long-term contracts, they are going to be a bit higher than the spot rates. Those are locked in rates. As time passes and new rigs come on, the rates under those contracts will actually increase a little bit over the quarters with the new bills coming on over the next year.

That's helpful. Could you give us a feel for, obviously, activity overall for industry has come off sharply and has continued to do so over the past few weeks. Are you seeing any stability in terms of customer inquiries or anything that gives you a feel for what the next month looks like?

Jeff, this is Doug. Certainly the rig count, as we said, has dropped faster and quicker than I think we all thought it might under the circumstances. I don't think, at this point, we have any idea how much deeper it is going to go. John and I were at a conference last week and there was speculation all over the map as how deep does it drop. I think the reality is we don't think we have hit bottom yet. There still to this point has not been a whole lot of inquiries on wells or programs. I think our customers are still sorting through their 2009 budgets and trying to determine just how much they want to do. I think the real problem we have, Jeff, that with commodity prices where they are today, there is just no incentive for our customers to drill into this market, and we have seen some indication, a well here, a well there but certainly the majority of the big drilling programs we haven't seen that sort of activity come back at this point.

My last question, your balance sheet is in very good shape. You obviously built another $50 million in cash in the first quarter. Are you viewing this year as a consolidation opportunity for you guys, or do you prefer to stay your course with your new rig designs?

I think that the way we look at it is that historically the management team that's in place in our Company has been able to build value coming out of down cycles. I think we have added a huge amount to long-term value of the Company through these kinds of transactions. Right now, it appears that it may be early, but we are certainly looking for opportunities in this environment and think that that balance sheet that you spoke about is one of the reasons why we'll have those opportunities. The other is the ability, fundamentally, to manage our business in a sound way, the scalability that I spoke about, and the opportunities that that will present.

Alright, thank you very much.

Our next question comes from the line of Dan Boyd with Goldman Sachs. Please proceed, sir.

Hi, thanks. Can you talk a minute about the economics of some of the buy-outs that you are seeing on the contracts and what impact that might have on the day rates for 1Q? I noticed in your -- in the press release you put in guidance there the average revenue per day would be less than $500 over the fourth quarter. What impact do you expect to come from contract cancellations?

Dan, let me maybe spend a moment -- I think that question is a good opportunity to make some comments about these contracts. Basically, these comments are take or pay contracts. Our customers, therefore, have the option at any given point of either taking the rig and paying for it or paying, typically, a buy-out fee that compensates us for, in effect, the margin that we would have otherwise received. The customers come to us often times and say would we like to discuss it, and we are willing to discuss those contracts with our customers and trying to find favorable outcomes for both parties. It is hard to speculate as to what buy-outs would occur, what changes will occur going forward.

Historically, we think we are at a very good position. We think it is more likely that our customers will take these contracts, take the rigs and drill the wells as contracted and that's what we are expecting will be happening going forward, in the vast majority of the cases. There may be exceptions, but that's what we anticipate will be the rule and not the exception and that's how we are operating. Of course, we are open to conversations with our customers at all times because that's the nature of the service business.

Okay. So, just to clarify, year to date you have not received any contract cancellation payment and that $500 decrease that a you are guiding to does not include anything of that nature?

That's correct.

Okay. Next question is more as we come out of this down cycle, I think we are all hopeful that gas prices one day improve from current levels. In the past, Patterson has been able to pick up a considerable amount of market share as rig counts are due to improve. How do you see that playing out this time given that there has been a mix-shift towards what rigs are preferred in the market given the shale plays? Do you see any change in that dynamic, and how are you -- how do you think the Company is positioned?

I think we are superbly positioned. I think we are going to do the exact same thing again. The rigs that we have available for customers are among our most technologically advanced rigs we have available. These rigs are perfectly capable of drilling the horizontal shale plays that are available. We think we have got an advantage because of our field capabilities. And here I would just like to take a moment to salute our field people, because they're just spectacular, and that capability in the field is what allows us, we think, to get a jump start on the industry when rigs go back to work. We think that we have the rig fleet to do that. Make no mistake, we have invested a substantial amount of money over the last several years building the kind of fleet that we expected would be needed going forward, and that's where we are. Doug, I don't know if you want to add anything?

Yes, I think I'd add a couple things. Almost every market has been hurt. When we look at the analysis of the rig count drop, it is hard to single out one region. It is hard to single out any particular size of rig. We have as many quality rigs down today. We are actually surprised by that. In fact, I think I said earlier that we were a little bit surprised at the somewhat indiscriminate reduction in rigs, price, performance didn't apparently seem to make much difference. I think our customers were, quite frankly, just trying to get rid of a cost wherever they could, and obviously the customers that had long-term contracts those rigs were difficult to get rid of. Just like some of our competitors, I think we have a number of rigs down today that we are surprised that they are down. We think we are very well positioned as this market does start to turn up. We have prove in the past, and we will prove it again that we do have the capability of, as John calls it, scalability, both up and down, and very quickly we feel we will be posed to react to that and take advantage of it.

Okay. That's very helpful. One last one, if I can. There is a lot of talk out there that day rates, if you are actually signing any new rigs, they are close to cash break-even levels or near there. Can you comment on that? And then also, just some experience in coming out of some of the prior down cycles, what you saw in terms of -- what did it take in terms of utilization or drilling activity before you start to see day rates increase again once they reach cash break-even levels?

Well, let me address the cash break-even comment first. We have certainly seen some of that. I don't think it is widespread. I think in this industry you're always going to have some people, particularly those smaller players and interestingly enough some of those have a significant amount of debt that they feel utilization is far more important than actually turning a profit. And that has never been our philosophy. As you know, we always try and keep a reasonable amount of market share, but at the same time we do try to maximize our margins.

I think there is kind of a story on every street corner about so and so might be working at cash costs. I think you need to be careful with making a generalization that that is across the board. Certainly, when you talk cash costs, there is a lot of different contractors that have a much different level of a cash cost level. Again, I think we -- I think even if you looked at the last two downturns, we did not get down to cash cost levels, or if we did it was for a very, very short period of time. I think the fundamental answer is this business, particularly I think with new advanced technology rigs, the cash cost to run these rigs are significantly higher than those last two down cycles, and I don't think the industry is prepared or should, quite frankly, work rigs just for the practice of it. As you know, these new advanced technology rigs are expensive. They are expensive to maintain and the industry needs to get a decent return from them

Okay. Thanks, I appreciate it guys.

The only thing I would add to that, and it's really a small comment to echo what Doug has said, but Patterson historically has had among the best abilities to manage its costs. So, we think that we will be able to do that again in this cycle, and we think that will give us some competitive advantages.

Our next question comes from the line of James West with Barclays Capital. Please proceed, sir.

Hi, good morning guys.

Good morning.

Mark or Doug, at this point as you think about balancing the market, and in your position as really one of the swing providers of a lot of the capacity, how many rigs that may show up in your fleet count are actually not marketed or stacked out at this point?

John, do you want to respond to that?

The 347 rigs currently marketable that we mentioned in the press release, those are all available to work and ready to work. We do not maintain crews for those, but as the market increases we would bring those back when the demand is there. Does that answer your question?

I guess how many don't have crews then maybe is a better way to ask that?

Okay. Well the answer there would be that we only maintain crews for those rigs that we're working. Over the last several months as rigs were stacked, rigs properly stacked out over a day or two, and if we do not have further demand for the rig, those employees are -- leave employment with the Company. That's the scalability that Mark and Doug have been talking about.

Okay, that's helpful. A second question, I know you just reviewed your fleet and you do it every 12 months or so, would you think about retiring assets, and you retired 22 or so rigs this time. Before looking at a market, let's say that is depressed for all of 2009, and we get to the end of next year and the 2010 market doesn't look much better, how many rigs at this point or when you went through the review recently were on the fringe that would be retired at that point?

We really can't answer that. We review our fleet every year. We would have again another look at it next November or December. The reality is today, we felt we retired the rigs that we wanted to take out of the fleet this year. I would say today, every rig that we say is marketable is a rig that we feel can work and we feel likely will work some time in the future.

Okay, that's helpful. Thank you.

Our next question comes from the line of Arun Jayaram. Please proceed.

Good morning, guys. Arun Jayaram, Credit Suisse.

Good morning, Arun.

Guys -- or John, can you help us a little bit on the margins on some of the term contracts that you have? I think you cited 52 in the first quarter and averaging 37 for the year. Can you give us a sense of what the margins would be on those rigs?

You have really two groups of rigs under term contracts. Like everybody else we have signed term contracts at various states beginning in 2006, and some of those are rolling off. At the same time, you have new rigs coming on that were requested in 2008 to meet requirements like the Marsalis Shale. We really, truly avoid giving exact specifics of what we are getting from our customers on these contracts, but I think we have indicated before, and so have other competitors, that the day rates on those are in the mid-20s and the costs aren't dissimilar to other rigs. Most of these deals for us are three-year contracts. A couple of them are two-year.

Okay. Some were on the new ones in the mid-teens in terms of margins and the existing ones may be a little bit lower than that for existing rigs. Is that fair?

That's fair.

Second question is terms of your Q1 guidance, you expected revenue per day or day rates to be down $500. Help us understand how the cost side of the equation could look. Do you expect daily costs to be up because of fixed cost absorption, or can you hold that relatively flat?

We are assuming that we can hold that relatively flat, actually probably down a little bit from the fourth quarter. We are going to endeavor to further tighten up those cost numbers as times passes. To date, we have gotten we believe the full benefit of stacking rigs and eliminating the underlying costs of those rigs that were stacked. We will continue to look at our cost structure and see if we can squeeze down the daily costs as 2009 progresses.

Okay. Two other quick ones. Based on historical patterns, margins and cyclical troughs has tended to be in the $1,500 to $2,000 range, and the assumption is you want to get somewhat of a margin so if you burn up a top drive you don't want to work at true cash cost. Do you think that that's a reasonable assumption assuming the rig count goes down to 900 or 1000 rigs, just for the spot market?

Underlying the rigs that we have running is term contracts, which clearly have margins significantly above those tight margins. I would also point out if you go back to 2001 and 2002, only momentarily were margins down to the levels you are talking about. A customer showed a willingness on the spot rate rigs to provide us some return on that, but also point out that the rigs we have running on spot rate are generally a thousand horsepower or more. Many of them have top drives. This is very, very premium equipment that is working and generally we have not experienced margins down to the levels you have mentioned.

Arun, I just would be cautious about assuming that what occurred in prior downturns is a perfect indicator of what is going to happen in this time. As Doug and John have made reference to, the equipment that is being provided is very different in 2009 from the equipment that was being provided in 2002. The costs of both operating that equipment, as well as the capital costs that went into acquiring it are all vastly different. I think that making the kind of quick assumptions that are being made about rates going down to this kind of cash cost level is ignoring the sort of spectrum of rigs, and there is going to be a lot of thinking that's going to need to be done on the part of investors in respect of the kind of spectrum of rigs and the spectrum of pricing. So that's --

Okay. That's fair. But Mark, just putting those comments together, your expectation as you see it today would be that the trough margins would be higher than we have seen in history?

Yes.

Okay. That's exactly what I was looking for. Lastly, perhaps a little bit more of an aggressive CapEx number excluding some of the new builds where you have contracts for that I would have expected given the outlook. Can you walk us through that logic, and perhaps your expectation of when we do see a turn in the market?

Arun, I think as Mark mentioned in his comments, the $200 million of capital include some upgrades and also the additional horizontal track spread for the Marsalis. We think those are going to provide us with good returns, and of course you have some maintenance capital. The big piece for the capital budget for the year is the 22 new builds which will provide very good returns, we think, for our shareholders, appropriate extension and improvement of our rig fleet over time.

Arun, I might add something to that. Of that $200 million, approximately $80 million of that is for our continued rig upgrade capital program. Now, we have cut that back significantly over what we had originally had hoped to spend this year, and that part of it is still, to some extent, discretionary.

Right, right.

As the year unfolds, we will continue to look at that number, but we embarked on this program of upgrading the overall fleet three or four years ago and we want to continue to do that.

Okay. Makes sense guys, thank you so much.

It is also part and parcel of the idea that we have this competitive strength of our balance sheet. We have this ability to improve our business even during this downturn, and potentially to get to an even better competitive situation by investing in our business at this point, without debt.

Okay. Makes sense guys. Thanks.

Our next question comes from the line of Marshall Adkins with Raymond James. Please proceed, sir.

Good morning, everyone.

Good morning, Marshall.

Let's start off with -- I want to go back to the margin question in Q1. Normally it is pretty difficult. You guys do a better job than most, but it is pretty difficult to bring your costs down as fast as utilization is coming down. I heard you say you expect actually costs to come down pretty sharply, and so should we imply -- if revenues are down $500 or so that margins will go down $500? That would be pretty impressive management if that's happening. I just want to make sure I heard that right.

I think we meant to say something a little different than that. From the cost side we think we will get our costs down a little bit from the fourth to the first quarter, but that's $200 or so. The scalability, when those rigs go away, the related costs go away. We are going to take a further look at it and see if we can further tighten up our costs and bring down our costs per day, but I don't think we put any number with that. We view that as an opportunity.

In terms of rates, when we look at where we stand today relative to the fourth quarter, we think that overall average rates fourth to first quarter will go down less than $500, and I think that was the limit of our comments.

Yes, yes. That was pretty clear. That is helpful. If you are able to also bring cost down $200 then that would imply margins are only falling maybe $300 or so. That's what I was confused about.

Marshall, if you look at our Q4 numbers, if you look at the costs, you will notice that apart from the wage increase, we actually did a pretty good job managing our costs in Q4. That has been an ongoing program that we have had to really evaluate and review and manage those costs very aggressively. The two things that John mentioned earlier in past cycles when we have had the little dips, typically I think the industry has been slow sometimes to reduce the number of people quickly and we have been very aggressive doing that this time. And the second factor there is I think in past cycles, people took the opportunity, oh, the rig is down, I think I'll repair that drawworks or get those pumps in, and we have been very careful this time to make sure that we haven't been spending money on things that we feel we did not need to.

Sorry, what? That's --

All I'm saying is we have had a very aggressive managed approach to looking at our costs.

That's where I was going. That's pretty impressive that you are succeeding doing that.

Marshal, just to be clear, comments were on a revenue decrease and possibly a little bit of a cost savings. So taken together, we don't think margins will drop a lot from the fourth to the first quarter.

That's pretty good. That's real good.

Okay, shifting gears here. Your market share has fallen off probably a little steeper than most, and a lot of investors we have talked to, just assume that's because of the type of rigs you have. I would think there are other factors going into that, like the regions where you're strong, or the customer type you have, or more price discipline or maybe even the amount of long-term contracts. Help me understand how much of your market share loss you think is the type of rig versus other issues like price discipline and customer type?

Marshal, I mentioned earlier as we kind of watched this unfold and seeing that our customers have almost indiscriminantly released rigs, it is obvious to us they have released some of their best performing rigs, some of their most efficient rigs, and it is obvious to us that some of it has been with little or no regard to efficiencies or even the cost. As I have said before, some of our best and most efficient rigs have been laid down during this cycle. In my mind, I would say it has nothing to do with the age or quality of equipment. We have felt for quite some time that others had a higher percentage of term contracts and we have seen that borne out in the marketplace. The rigs that have seemingly got to stay working for customers have all had term contracts. We did see, I think initially some initial reaction that some regions got hit faster than others, West Texas for example, and I think predominately because of our accrued oil focus out there.

As you know, we have extensively upgraded our fleet over the last three or four years. We are very proud of the fleet we have got today, and I think with very few exceptions our fleet is good or better than the vast majority of the rigs that are in the US fleet. We do not feel that we have lost share because of the nature of our fleet, and I think if you look at the numbers today, we may have got hit very early and quicker than some of our competitors. We believe that was because of the term contracts, but if you look at the numbers recently, a lot of those other contractors have caught up and have seen a bigger hit than we have over the last month or 45 days.

That's very helpful. Good clarity there. Last one for me, you gave some good details on the CapEx. That's very helpful for our modeling, and pretty clear on the $320 million on new rigs, but the other $200 million, can you kind of break that down a little more detail? How much of that is what we call maintenance CapEx that you're going to have to do anyway versus the rig upgrade program versus fract fleet, et cetera?

The maintenance CapEx number is in the $55 million to $60 million range.

That's included in the $200 million, right?

Yes.

That is part of the $200 million.

Right. Okay. Good. That's what I wanted to get clear on. Keep going. Sorry.

I mentioned there was about $80 million that was kind of our remaining rig upgrade program, and our capital associated with Universal this year will be down about $20 million over what it was last year, likely in the low $40 million range.

Okay. That's --

Of course, we have about $14 million for the E&P business.

All right. That's --

Gather those things together, Marshall, it gets pretty close to the $200 million we are talking about, and obviously some of that is discretionary.

The $80 million of the upgrades is probably your most discretionary component I would assume.

Right.

Alright, great. That's all I needed to know. Thanks for the help, guys.

You bet.

Our next question comes from the line of Mark Brown with Pritchard Capital. Please proceed.

Hi, guys. Just one question I had is that when we do see this market start to see a supply response, I just want to confirm, you would think that the rigs that would snap back most quickly would be your best and most efficient rigs from new rigs or upgrades, or do you think it would be to some extent some of the lower end rigs that would be coming back?

It is kind of interesting. We see it more likely to be across the whole rig fleet, and different customers with different applications going for different rigs. That has always been our view about the overall rig market, and in fact the fit for purpose covers both the new rigs that are fit for some of the most technically challenging drilling as well as fit for purpose in terms of some of the in-field drilling that doesn't require such rigs. If there is this supply decrease and price increase which we think is kind of inevitable -- can't tell you when, but inevitable none-the-less, then we think that rigs across the board go back to work.

Okay. For the -- for your APEX rigs, do you think that when they are hired for -- any of them that aren't already on term contracts, do you think they would be more on the two to three year term contracts? The reason I bring that up is that an operator may not want to commit to that when we just start to see the turn upward in the market, they may prefer to pick up something on the spot market. Just wanted to see what your thoughts were on -- the extent to which the upgraded or new rigs would be put on term contracts when the market turns up?

I think that your comment is probably correct. That as the market starts to turn up, the participants won't be 100% confident and they may not want to make long-term commitments at that point. So, we think what you just said is probably correct. I think we have always been pretty flexible in trying to figure out how to maximize the returns for our shareholders, and at the same time do a good job for our customers, and I think we will be able to strike the balance between those two competing interests to find what will be a -- something that will maximize our profits and, at the same time, maximize the service to our customers.

Alright. Very good. Thanks a lot.

Our next question comes from the line of Kevin Pollard with JPMorgan. Please proceed.

Thanks. Good morning. My question, probably for you Doug, is around the APEX rigs. On the last conference call you guys indicated you had 34 additional APEX planned, and I think that 25 of them were contracted. Now you are talking about 22, all of which are contracted. I know you've had some deliveries since then, but were those -- were the last nine uncontracted rigs, did you ever secure contracts, or were they put on hold given the market environment?

Those nine that you are talking about, Kevin, were deferred. We did not have long-term contracts for them. We went back to our supplier and actually just deferred them. We do hope that over time we will have a need for those rigs again. Because we did not have a term contract for them, we felt that we did not want to go ahead and take delivery of them.

Okay. Makes sense. I just -- in terms of the CapEx spending the $320 million on the new rigs, is that going to be predominantly loaded into the first half of the year so you'd meet the delivery by year-end?

It is pretty much spread out pretty equally over the year. I probably would say there is a maybe a little higher percentage over the first three quarters. But, sometimes you get a lag time when some of the bills come in. In terms of deliveries, they are equalized over the four quarters.

Okay. Alright, that's all I had. Thanks, Doug.

Our next question comes from the line of Mike Irvin with Deutsche Bank.

Thanks. Good morning. Wanted to re-visit the contract issue a little bit, you talked about the -- some of the take or pay contracts that you have. What is your view if a customer does still want to take delivery of the rig that might want to renegotiate the rate or the term of that contract. Is that something you have done in the past, or would be willing to do, or would you try to stick within the original take or pay terms?

I don't think I can say anything here that's going to be extremely valuable to you, because each of these conversations is a separate conversation with each customer about each rig. We are happy to engage in those discussions with our customers. What we are not likely to be wanting to do is to give up the favorable economics that are built into it, but if we can strike a win win for our customer and for our Company, that is a great opportunity. So, we're always happy to engage in those conversations, but we're not -- if you are asking us whether we are expecting to be discounting those contracts or doing something else that's going to be sharply different from one of the terms, the answer is no expectations currently.

Okay. And you have addressed the day rate issue in a number of different ways. I was wondering if you could give us a sense as to what the leading edge rate may be, or is there no such concept right now just given that rates seem to be stacking out rather than renewing or going to some new kind of market rate?

I think that the market is -- the rig market, like financial markets, like so many markets right now is in a moment of trying to assess what direction it's going in. I mean, just a kind of a point of reference here, our rig count was going up through mid-October, and reached a height early October, and 275 was the number of rigs that was being run then. It is shocking to the participants throughout the industry to be at the current levels, and so I think when you say kind of what our pricing expectations, I think that right now people's expectations are that the market is looking for a new set of footings and once it finds those new set of footings we'll then be coming to some kind of new pricing. But to say that right today is going to be the pricing and the footings for the next two years strikes me as being -- or even potentially several months strikes me as a set of assumptions that I'm not sure I'm ready to buy into.

Yes. I would tend to agree. Last question, how many -- of the upgrade program, how many rigs are planned for upgrade this year?

Actually none. Other than the 22 new rigs, most of the rest of the upgrade program is primarily related to things like top drives, new math, new sub structures, our continuation of our pump program.

But not necessarily --

We are actually not refurbishing any rigs this year, other than the brand new rigs that we're --

Okay. No total overhauls, just more adding, adding equipment and things.

Unplanned.

Okay. Great. That's all for me. Thanks.

Our next question comes from the line of Geoff Kieburtz with Weeden. Please proceed.

Good morning. Thanks.

Hi, Geoff.

I think you may have already addressed this, Doug, but you mentioned that in the first quarter you have got six new rigs coming in on term contracts, seven old contracts rolling off. Could you fill in the schedule for the remaining three quarters of '09?

Geoff, I don't have that right in front of me.

It sounded like from your earlier comment we should be getting roughly six new builds in the second and third quarter, and maybe it drops off to four maybe in the fourth quarter and then --

We are pretty close there. We are looking at probably six in the first quarter, seven in the second quarter and then five and four, and in terms of existing term contracts coming off, we do have a number of term contracts coming off in Q2. I don't know that I have the exact number in front of me.

Right. It must accelerate because you are starting out at 52 and you averaged 37 for the year, so maybe I can back into it anyway. In regards to these term contracts, when -- what is the relationship between the margin on an old contract that is rolling off versus a new contract on a new build. Are they roughly the same?

Geoff, the margins on the new ones coming on are a bit higher. What happened in the industry is people began to build new rigs four years ago.

Yes.

Initially the rates on those were a bit lower, and frankly the equipment was a bit less expensive. I think the contracts that were entered into by the various land drillers in the US during the first half of 2008 had higher rates, as mentioned earlier, in the mid-20s or so. If you go back to some of the earlier years many of those contracts were in the $16,000 to $20,000 a day rate. The rates are actually bumping up as the new rigs come out, probably for each of the drillers. The average for those going down because you have older ones rolling off.

You have made, several times, the point about the variable cost nature of the land drilling business. But then we have also heard a number of operators commenting on the -- we have 2004 commodity prices and 2008 cost structures. Just narrowly talking about the rig market, the average day rate for Patterson in '04 was something -- approximately half of what you posted in the fourth quarter. How do you engage in the conversation with your customers when they start with this, hey 2004 commodity prices and 2008 cost structure?

Geoff, I will turn it over to Doug in just a second for how we talk to the customers, but I guess I'll point out we indicated earlier we are going to endeavor to try to lower our cost per day.

Right.

But, realize that the rigs that are running today are different sets of equipment. We are constantly upgrading our fleet to meet the customers' needs. They have top drives, they have iron roughnecks, they have lots of things that cost more per day to operate than they used to. However, we're trying to maximize margin for shareholders and be competitive on price, so we will work to lower our costs per day, but we haven't put a dollar amount on that, but we will be endeavoring to do that.

Besides that, Geoff, and I agee with what John just said, we drill different kind of wells today. The horizontal plays that are now a significant part of our activity wasn't the same drilling that we were doing back then.

Sure.

Number two, we drill those wells more quickly with different kinds of equipment, and so the customer is really evaluating the cost of the well and not necessarily the cost per day of drilling.

Right.

Frankly, some of the other associated costs with wells that we see through our E&P experience are some of the ones that have actually been the ones that have gone up the most, and the drilling costs are typically not the part of the equation that is really driving the customers' costs. I think your point about customers saying hey, look, I'm getting a lower commodity price and I have got to make sure that I do what I can to get my service costs in line with my commodity costs, or my commodity pricing, makes some sense but I don't think we are the primary whipping boy for that problem. There are a lot of other costs in the equation that have gone up and are significantly more than ours.

Geoff, I would add one thing. I have been in the drilling business on and off since the mid 1970's, and in this latest cycle for the first time in my career in the drilling business, I have had customers say to me, Doug, it really doesn't matter what your cost is for your drilling rig, you guys are not the big component of the cost anymore. We've had people say you could charge me nothing and I still wouldn't drill these wells.

Right. Okay. Doug, you mentioned that 10 of the 22 new rigs coming in '09 are targeted for Appalachia. Press release commented on the ramp up on the Marsalis being slower than expected. Any concern there that these 10 rigs that are slated for the Marsalis may not be needed?

I don't think so. They are all spread out over at least four different customers. I won't name the customers, I think you know who they are.

Sure.

These are all rigs that, quite honestly, these plans and programs were put in place 12 to 18 months ago. It has taken this long for us to get the fit for purpose type of rig built that they are looking for up there, and from the customers that we are dealing with they are all very encouraged, and I think everybody feels that there is a lot of promising work to be done up there. We are not concerned that -- we hear numbers of rigs that are moving into that market. We think these 10 fit for purpose rigs are going to be ideally suited for the drilling up there.

Okay.

If I can just add one more thing, Jeff, that kind of goes with that. We have got a lot of experience in that marketplace from Universal Well Services, having been in that marketplace and been a very significant player in that marketplace, and one of the things we have learned through Universal is that both the geography and geology of the area are different, and the equipment that necessarily works in other areas isn't easily adapted to work in that area. The result is that you need equipment that is specially designed and uniquely positionable for that kind of marketplace, and we think we have done it both on the fract equipment side as well as on the drilling side.

Right. Mark, one final question, when you were talking about the capital spending and program to ensure that the fleet is matched to the customers' needs, I think you made a comment about without debt. Were you saying there that the spending at Patterson in '09 would not exceed cash flow?

The short answer to your question, Jeff, is that based on the work we have done, we don't expect to be in a borrowed state at the end of the year.

Okay. Great. Thank you very much.

Our next question comes from the line of John Daniel with Simmons and Company. Please proceed.

Hi, guys. Just a few questions on the pumping business. Are the margins that you are getting on the new horizontal fract work, are they materially different than the traditional work?

Margins are in the same range. I think what you have to recognize is these jobs are much bigger, in fact --

Yes.

They are almost 10X in terms of both horsepower and the revenue.

Okay.

Overall, the margins are significantly higher, but on a percentage basis they are certainly in the same ballpark.

Okay. Speaking of the horsepower, you mentioned you have got a few pumps come in this year. Once those are all in, what will your final horsepower be?

The exit rate for '09 will be pushing 130,000 horsepower.

Okay. And last but not least, at this point we have heard lots of companies talking about moving assets to better performing regions, have you seen some of your larger pumping competitors start to transfer assets up to Appalachia?

Well, that's been an on-going process. We have actually seen it for the last couple of years, people moving in and out. All the major players are there. They are all capable of doing it, and so far the volume of business really has not supported a mass, I guess input of equipment in that market.

Okay. Thank you. That's it for me.

Our next question comes from the line of Allen Long with Bank of America. Please proceed.

Good morning, guys.

Good morning, Allen.

I've got a follow-up to Jeff's question on the balance sheet side, or the cash flow side. You always have a great balance sheet. No question there. Activity is kind of bad. Kind of -- really bad. Credit is pretty tight, and you have about $130 million, I think you said, in cash and you are spending $530 million. You did cut the dividend, which should keep you from drawing on your revolver in any significant way. How are you looking at the renewal of that revolver at the year end, or any thoughts around what you'd expect on the renewal size or term? Do you really need $375 million?

We really need $375 million. We've -- off the top of my head, I don't think we have ever been borrowed more than $100 million in the life of that thing. It has been around for a very long time. We expect to renew the facility at the appropriate time. It is a working capital line. It could also be used for opportunities for other things, but we would expect that we can renew it at levels that'll be appropriate and support our business.

Okay. How much working capital do you think you can claw back in the slow down? I think you have over $300 million out there right now.

I guess when you say reduce working capital, how much will convert to cash, because it's cash I think is the working capital. Certainly as the activities declines, we will see a meaningful move from receivables, net payables, toward cash. It really depends what you think the rig count is going to be and how that will progress, but certainly to say that $100 million or more will convert to cash I would think would not be an unreasonable assumption.

Okay. Are there any risks out there to any of your receivables right now?

You know, we have not had -- the last, I don't want to call it significant because it wasn't that significant given our size of Company, but the only big item we have had a problem with in the last seven or eight years was about a $4 million receivable which we ultimately would collect about $1 million of a $3 million individual write off. Everything else has been much, much smaller and hasn't been a problem. We work for the big independents. We work for a lot of very strong smaller independents. We are careful about who we work for, and we have not had significant losses on receivables in the last, I would say, ten years.

Sure. That's great.

This is Doug. I would like to add one thing. We work very hard at watching our receivables. We are concerned in this environment. But I am pleased to say that in Q4 our DSOs actually went down a couple days.

That's great. That's really good. The last question -- more of a scoping question in terms of how you would think about this, but some of your peers are issuing bonds as a safety cushion it looks like, or against future maturities over an extended downturn. You don't have maturities, obviously. Is there any interest on your part to issue debt to cash up to take advantage of any opportunities that may arise? Because it looks like you may have some road kill given the depths of this slow down.

Let me respond to that, Allen. I hope that we are always looking at our balance sheet, and trying to see what the opportunities sets apart from the -- it could be achieved with our balance sheet. So the short answer is do we think about that? You bet. All the time. We try as best we can to manage both the profit and loss and the balance sheet, and that is the thing we think gives us some competitive advantages, frankly, in the overall marketplace and with our shareholders. Ultimately we have been able to get extremely favorable long-term shareholder returns by being able to manage both sides.

Well, you are certainly better positioned than many of your peers. That's for sure. That's all I have.

Our next question comes from the line of Andrew Coleman with UBS. Please proceed.

Good morning. I had a question on your Marsalis pressure pumping operations there for Universal. Is that spread pretty evenly across Pennsylvania, or is it primarily on one side of the state versus the other?

It is pretty much spread through the Appalachians, it is not just Pennsylvania. We operate in New York, we operate in West Virginia. We have a total of about 12 different camps that we operate out of. We are not just limited to Pennsylvania. I think you have heard of us talk the Huron Shale tends to be non-Pennsylvania. It's certainly part of Pennsylvania, but we are probably spread out over five to six states.

Okay. Are you seeing -- I heard stories about kind of difficulties getting prop in other parts of the US, more like Texas. Is that being alleviated, or are you seeing those same issues up in the Marsalis?

The big market there has been primarily sand fracts, and certainly last year there was some shortage of supply in sand. We have done some things internally to try and assure our sources of sand. I think as the Marsalis develops, just like the Barnett and the Hainesville, you will see some science projects on how these fracts are completed. But, so far the issues have been sand and water.

Okay.

I think the water issue in particular has been the one area that I think things have developed slower because of the concern of citizens about the usage of water. We believe those issues are being addressed and will get resolved.

Alright. Thank you. Then a question on -- there was an earlier comment in the call here it said something like 10,000 folks have left the sector there over the last few months. How much further do you think that goes before it starts to eat into some of the core institutional knowledge that the drilling companies possess?

I don't think we said 10,000.

Someone else did.

Somebody else? I'm sorry.

If you think back over the different cycles that have occurred, we had a low period in 1999 and we had a low period in 2002. It appears clear at this point we are going to see a low period in 2009. It isn't easy, but our operations people have been able to attract the talent they need as the market recovers. The people's rigs are stacked that tend to be sent home are the less experienced, and we always endeavor to keep the talent we need to be able to come back and run the number of rigs that we have. That is the nature of our industry. I think Mark spoke to it in its opening comments about scalability, and this is a two-way street and we have lots of experience in managing that process.

Okay. Last question, I forgot, I wanted to step back to the pressure pumping issue. How big is the backlog, and is that going to persist you think past the second quarter?

This business we don't traditionally speak to backlog. Typically, we will have a work board in each one of those camps that would have the jobs that were projected out for maybe the next couple months. Customers typically don't get too much beyond that in terms of saying, hey, put me on the list for next November. That just doesn't happen because of the, you know, the well has to get drilled first. As I said, we don't typically talk about backlog. The one thing that we have said is that the traditional business in the Appalachians, which tended to be fairly shallow, fairly simplistic wells with the industry focus on the Marsalis and the Huron, some of that business has retrenched somewhat, and we have seen that impact our numbers. In some cases it has been more than off-set by the refractoring and the cementing and the nitrogen jobs on the Marsalis and the Huron Shale -- wells.

Okay. Thank you.

And our next question comes from the line of Jud Bailey with Jeffries and Company. Please proceed.

Thanks. Good morning. A follow-up from an earlier comment. Doug, I believe you said that nine of your new build rigs have been deferred. To the extent you choose to go fore with those, whenever that may be, do you keep the same construction agreement, or construction price, or would you benefit if construction prices begin to come down?

I'll answer that, Jud. The answer is that the pricing would modified in accordance with with the current conditions.

Okay. And do you have any comment to the extent that things have changed on the pricing front for new construction?

It would seem that steel costs have gone down, and other costs have gone down, so we expect that our costs are going to go down.

Okay. And to the extent --

Go ahead.

I'm sorry, I was going to say. To the extent you're in the market for replacement cost and upgrades, can you comment on any reductions you're seeing in equipment costs for secondary -- or for second-hand equipment?

I think at this point it's -- we haven't seen those costs come down significantly. I think as this unfolds we will see some of those things, and as Mark said steel costs certainly are probably the biggest part of that. But, you've also got labor costs with welders and associated people that we expect over time are going to come down.

Okay. That's all I've got. Thank you.

Our next question comes from the line of Arun Jayaram with Credit Suisse. Please proceed.

Hi, guys. My answer was -- my question was answered. Thanks.

(Operator Instructions) Our next question comes from the line of Mike Clark with Sur Capital. Please proceed, sir.

Hi, guys. Sorry to prolong the call. Just wondering very quickly what your G&A costs are and what your SG&A expectations are for the full year. Thanks.

John?

I'm looking for the wrong thing here. Hold on. In terms of the G&A costs, again, with the downturn we're taking a look at every cost and seeing what we can squeeze out of it. Not having completed that work at this point, I would venture a guess that at current levels G&A will run about $16 million, maybe $16.5 million. In terms of depreciation, depletion, amortization including all of our business units, my guess would be about $73 million.

Thank you, very much.

There are no further questions in queue at this time. I would like to turn the call over to Mr. Siegel for closing remarks. Please proceed, sir.

Thank you. I would like to thank everybody for their participation. Look forward to our calls at the end of the first quarter. Thanks, everybody.

Thanks for your participation in today's conference. This concludes the presentation. You may now disconnect, and have a great day.