Patterson-UTI Energy Inc (PTEN) 2010 Q4 法說會逐字稿

Good day ladies and gentlemen, and welcome to the fourth quarter 2010 Patterson-UTI Energy Incorporated earnings conference call. My name is Katelyn, and I will be your operator for today. At this time, all participants are in listen-only mode. Later we will conduct a question-and-answer session. (Operator Instructions). As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the presentation over to your host for today to Mr. Geoff Lloyd, on behalf of Patterson-UTI Energy. Please proceed.

Thank you Katelyn. Good morning, and on behalf of Patterson-UTI Energy I would like to welcome you to today's conference call to discuss the results of the three and 12-months ended December 31, 2010. Participating in today's call will be Mark Siegel, Chairman, Doug Wall, President and Chief Executive Officer, and John Vollmer, Chief Financial Officer.

Again just a quick reminder that statements made in this conference call that 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 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 availability, 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 by obtained by contacting the Company or the SEC. These filings are also available through the Company's website, and through the SEC's EDGAR system. The Company take undertakes no obligation to publicly update or revise any forward-looking statements.

Statements made in this conference call include non-GAAP financial measures that require reconciliation to GAAP financial measures are included on the Company's website, and in the Company's press release issued prior to this conference call.

And now it is my pleasure to turn the call over to Mark Siegel for some opening remarks. Mark?

Thanks, Jeff. Good morning, and welcome to Patterson-UTI East conference call for the fourth quarter of 2010. As is customary I will start by discussing some of the big-picture highlights, and quickly review the financial results for both the three month period ending December 31, 2010, as well as the results for the year. I will then turn the call over to Doug Wall, Patterson-UTI Energy President and CEO, who will make some detailed comments on each segment's results, as well as sharing some operational highlights for the individual operating units for the quarter. After Doug's comments, I will share a few brief thoughts on the market outlook. As always we will be pleased to take your questions following these prepared remarks.

At the outset, let me say that we were very pleased with our results from both of our core businesses during the fourth quarter and for calendar 2010, in both businesses, we saw a continuation of strong demand for our services, which of course leads to pricing improvements. In the fourth quarter, we expected strength but were surprised in a positive way with margins in the drilling business, and overall demand for pressure pumping services. Both exceeded our high expectations. Moreover, the strategic diversification of our Company is now apparent, as approximately one-third of our revenue and operating income in the fourth quarter came from our second core business, pressure pumping.

In terms of our drilling business, we have now seen 20 months of consecutive growth in our US rig count. Of course, we put out a press release yesterday which shows that our rig count continued to climb during January. Our continued increase in active rigs demonstrates that our rig fleet, both new advanced technology rigs and conventional rigs, are important for satisfying our customer's diverse needs.

Moreover this occurred despite low natural gas prices during 2010. Strong crude prices have caused new oil and liquids directed drilling to reach a high point not seen since the 1980s, and we with our rig and geographic diversity, have been able to capture a strong share of the rebounded market. For us, approximately 50% of our active rigs are now drilling primarily for oil and liquids. We are very pleased with the increase in demand for rigs for oil drilling, as we believe this market may be on a long-term basis more stable as oil places appear likely to remain high.

Our pressure pumping business had another good quarter, but direct comparisons are not possible for us, because this is the first full quarter of recognizing the revenue and earnings from our recently acquired pressure pumping assets. In terms of expectations, we said on our last call that we expected revenues for the pressure pumping and wireline businesses to be in the range of $140 million to $150 million. Ultimately pressure pumping revenues exceeded the upper range by approximately $6 million, even with the wireline revenues excluded. Prices for our services continue to increase, and we are extremely optimistic about this business going forward, both in terms of revenues and margins.

As set forth in our earnings press release issued before market this morning, we are pleased to report this morning that the Company reported net income of $53.9 million, or $0.35 per share for the three-month period ended December 31, 2010. This compares to a net loss of $18.2 million, or $0.12 per share for the comparable period in 2009. I should point out that excluding the impact of the transaction costs, both the costs associated with the acquisition completed on October 1, 2010, and subsequent disposition of the wireline business, earnings would be $0.37 per share.

Revenues for the quarter were $506 million, compared to $214 million in the same quarter last year, an increase of $292 million. On a sequential basis, revenues in the fourth quarter improved by $127 million from the third quarter, or approximately 34%. We were very pleased with the sequential revenue growth with drilling reporting an improvement of 17%, and pressure pumping revenues almost doubling. The growing significance of pressure pumping, approximately one-third of income and margins, is starting to change the way investors perceive our Company.

EBITDA for the quarter improved to $189 million, which represented a $51 million improvement over the preceding quarter. This substantial sequential improvement in EBITDA can be attributed to three elements. Number one, the positive impact of the acquisition of the pressure pumping assets. Number two, very solid margin improvement in the drilling segment, and number three, further improvements in our rig count. For the quarter, capital expenditures were $224 million. Much of this CapEx relates to our Apex rig new build program, which had a very busy end of year with seven rigs being completed during the fourth quarter.

Looking quickly at the year as a whole, we concluded 2010 with revenues of $1.46 billion, up from $782 million in 2009, an improvement of 87%. Net income for the year was $117 million, versus a loss of $38 million a year ago. Earnings per share increased to $0.76, versus a loss of $0.25 in 2009. EBITDA for the year was $536 million. Capital expenditures for the year totaled $738 million.

All-in-all 2010 turned out to be a year of great transformation for Patterson-UTI. We saw our US rig count increase by approximately 75 rigs from start to end. In addition to the 19 rigs we added to our fleet, we put approximately 56 other rigs back to work in the US. The shale plays and renewed interest in oil drilling drove much of this activity in both segments of our business. Horizontal completions and higher service intensity continue to drive activity levels in the pressure pumping business.

In addition to dealing with the activity growth in both of our core businesses, we also accomplished a number of other significant things during the year. We sold our drilling fluids business in January, we sold some oil and gas interests throughout the year. We completed the acquisition of Key's pressure pumping business in October, and shortly after year end we sold the wireline business.

In terms of financing, we obtained a new and larger facility, and we completed a private placement of ten-year debt with an under 5% coupon. Throughout the year we continue to improve the quality of our equipment fleets in both drilling and pressure pumping, and we did all of this while undergoing a corporate-wide IT systems conversion. All-in-all a very busy and productive year, one which we feel has transformed our Company for the future. This transformation has seen our focus become every sharper, laser-like, as we concentrate on our two core businesses. We believe there are excellent opportunity for investment in these businesses, and we continue to expand our equipment and people in both.

I would now like to turn the call over to Doug, who will further discuss our operations for the quarter.

Thank you, Mark. We will start this morning with some commentary on the drilling company, and then follow-up with some further comments on pressure pumping.

First with drilling, for the quarter ended December 31st, 2010, the Company had an average of 194 rigs operating, this included 182 in the US, and 12 in Canada. This was a 12-rig increase in the US, or roughly 7% over the activity levels we experienced in the third quarter. The overall industry land rig count in the US increased by only 2% during the quarter, so once again Patterson-UTI gained some added traction and share in the marketplace.

Perhaps the most pleasing change in the quarter came on the pricing front. Rig pricing continued to improve during the quarter with significant price increases across the rig fleet. The increasing demand for rigs destined for the oily basins, such as the Bakken and West Texas, has always helped to improve our overall pricing. As one might expect, this pricing momentum comes not only from the spot market rigs, which currently account for about 60% of our active rig fleet, but also from term contract rollovers at better pricing.

We still have additional rig capacity capable of going back to work in many regions, particularly West Texas, Mid-Con, and the Rockies. Overall we believe we are very well-positioned to benefit from any further incremental demand, particularly in the liquids rich and oily basins of the US. We continue to see customer interest in our high quality conventional rigs, and we expect to see additional demand in this area in the coming months.

Let me turn to look at some numbers for the quarter. Average revenues per operating day during the fourth quarter were $19,090, compared to $17,730 in the third quarter. This was an improvement of $1,360 per day. Average direct rig costs per operating day increased $330 to $11,000 for the third quarter, compared to $10,670 last quarter. Daily drilling margins increased slightly better than we expected, improving by $1,020 per day during the quarter, which was approximately $300 per day higher than we estimated in our last call.

Higher than expected numbers in revenue can be attributed to better pricing in the US, as well as higher utilization and rates in Canada. We also saw some impact from a pass-through of increased wages in certain markets. These higher wages also explain some of the increase in our daily operating costs. Overall, the US rig count continues to move upwards with as you might expect, a lot of the activity focused on the oily and the high-liquids areas. Although we keep hearing about a projected slow down in gas directed drilling,the overall rig count has remained on an upward trajectory, and the increase in oil-related drilling so far has more than offset what little shift we have seen away from gas-directed drilling.

Canada is now in full swing with its winter drilling season, with 17 rigs currently working. We should point out that the current rig count is several rigs higher than we have seen over the last three years. As a result of the expected seasonal decline in March, we expect the Canadian rig count to fall off as the quarter progresses. In total we now expect to average 205 rigs for the first quarter. Average revenue per day for the quarter is expected to increase by approximately $900 per day, and average daily drilling margins are expected to increase by approximately $500 per day.

Let me make a few comments on term contracts. I am pleased to say that we made excellent progress during the quarter by signing up 24-term contracts, including four new builds. During the fourth quarter, we had an average of 69 rigs working under long-term contracts. Based on contracts currently in place, we expect to have an average of 86 rigs working under term contracts during 2011.

I would like to give you a quick recap of our 2010 new-build program. In total, we completed seven new rigs during the fourth quarter. All of these are on long-term contracts. Of the seven rigs completed during the quarter, four were Apex 1500s, and the other three were Apex walking rigs. Of the total, two are working in East Texas, two in the Eagle Ford, two in the Rockies, and one in the Marcellus. For the year in total, we have completed 19 new rigs.

We now expect to complete 25 new rigs in 2011. This includes the rigs that have carried over from our 2010 program. We currently have term contracts signed for 12 of these rigs, but do expect to sign additional contracts in the near future. In essence we are now sold out of delivery slots through mid-year.

That concludes my remarks on drilling, so let me turn now to our pressure pumping business. Revenues in our pressure pumping business totaled $156 million for the quarter,almost double what we had reported last quarter, and better than we had expected. EBITDA for the pressure pumping business totaled $49.1 million.

Let me make a few brief comments on each region. We are extremely pleased with the performance from our newly acquired pressure pumping business in Texas. Revenues and operating profits were better than we had forecast. Demand and pricing continues to remain strong in the Texas market. In terms of pricing, frac discounts improved during the quarter, and we expect this trend to continue over the first quarter. We ended the year with an excess of 187,000 frac horse power in the Texas markets. We did not add any new equipment to this market during the fourth quarter, and no new equipment is expected until the second quarter of this year.

I am pleased to say that subsequent to quarter end, we signed a two-year term take-or-pay contract with a major operator in south Texas. We are very pleased to enter into this major commitment,and are currently in discussion with several other operators who want to commit to a dedicated frac crew on a longer-term basis.

In our pressure pumping business in the Appalachians, our quarterly results were impacted by the severe cold and stormy weather. Seasonal delays and shutdowns this year were much greater than we have seen in the prior years. Those snowstorms and cold weather you have seen on the weather channel were certainly for real. We estimate the revenue impact of these delays to be in the range of $7 million to $8 million.

During the quarter, we completed 30 Marcellus horizontal fracs, which was a decrease of five from the previous quarter. We also pumped 27 horizontal nitrogen stimulation jobs, which was very pleasing,and most of that work was in Eastern Kentucky. Although frac revenues were down quarter-to-quarter, our cementing revenues were up over 5% sequentially, and revenue from flow-backs and testing was up almost 15%.

During the quarter we continued to take delivery of equipment required to flush out our third quintaplex frac spread. We now have a total of 34 quints in service in this market. We expect an additional 11 quints to be delivered in the first quarter of this year, and just like we saw in Texas, we are extremely pleased this morning to announce the signing of a three-year term contract, with one of our crews in the Appalachians. We expect this contract will provide us with a significant amount of revenue and earnings.

Obviously, we continue to be very encouraged by the ramp-up in industry activity in the Appalachians, and feel we are extremely well-positioned to service this market. We have opened up our new facility in Williamsport, which houses our Northern Marcellus operations. We do expect to see further efficiencies in our operations by placing our crews, materials, and equipment closer to this growing market.

Before I turn the call back to Mark, let me make a comment or two on our expectations for our pressure pumping business in 2011. As we continue to see demand for frac capacity in a number of different markets, and a willingness on the part of our customers to explore contractual means of committing this equipment on a dedicated basis, we have placed orders with our suppliers to add a total of 204,000 horsepower to our frac fleet in 2011.

Other than the impact of the 11 pumps to be delivered to Universal Well Service in Q1, we expect the balance of these new deliveries to be fairly evenly split over the remainder of the year. To put this all in perspective, we now expect to end 2011 with approximately 560,000 horsepower in dedicated fracturing capacity. With approximately 650,000 total horsepower, which includes our nitrogen and cement units, we have become a significant player in this business.

So with that, I will turn the call back to Mark for some concluding remarks.

Thanks, Doug. We are very pleased with the operating and financial results for the quarter, as well as the tremendous progress we made on a number of strategic fronts last year. We remained bullish about the prospects for the energy business in North America, and have been pleasantly surprised by the resurgent interest in oil and liquids driven drilling. We are constructive of respective oil prices generally, and think that North American oil reserves are likely to continue to be especially attractive.

In respect to the natural gas business, we think that our customers are adjusting to the new normal respecting natural gas prices, and all of the industry players are determining their strategies for making this current pricing paradigm work for them. As Doug said, we have plans for adding significant new equipment for both the drilling and pressure pumping businesses. Our 2011 CapEx plans call for us to spend approximately $900 million, including approximately $220 million for pressure pumping. This CapEx plan demonstrates our fundamental confidence in the opportunities in our core businesses.

As we have said before, our industry has changed dramatically over the last several years, with a focus on unconventional plays, and the advent of new horizontal drilling and completion techniques. Patterson-UTI has reacted and responding accordingly. We have transformed our Company with the addition of new high technology rigs and higher horsepower frac equipment, to take advantage of the higher service intensity required by the types of wells we are drilling and completing today. We see these trends continuing, and are positioning ourselves to be a leader in both of our core businesses. We are however, cognizant of the oil industry's penchant for overbuilding capacity, and are keeping a very close eye on customer demand, oil and natural gas markets, and the overall supply chain.

We believe that we can continue to generate high rates of return on these new assets. If however we see a change, we will not hesitate to reduce spending. Upon completion of the planned 2011 capital program, we will have a fleet of almost 100 new advanced technology Apex rigs. Our Walking Rig technology is thought to be the best in the industry. Theoverall drilling fleet has undergone major improvements and enhancements over the last few years.

On the pressure pumping side, the acquisition of the pressure pumping assets, and our ongoing new capacity frac crew additions, gives us one of the youngest fleets in the industry. We are very well-positioned in three of the fastest growing markets in the industry, the Marcellus, in south Texas, and WestTexas. We believe that we are generally familiar with the new equipment additions in the US pressure pumping market, and want to share with you our reasons for optimism, despite these additions. Number one, the service intensity, number of stages, and required horsepower just keeps growing. Number two, equipment is wearing out, and must be replaced at rates we have never witnessed before. Number three, the supply chain is currently highly restricted, with customers having long waits for the desired equipment and crews.

For these reasons we are less concerned than some others people seem to be with respect to this issue. There is no question that the drilling and stimulation markets have changed dramatically over the last few years, and so has Patterson-UTI. We have repositioned our Company to respond to these changes in the market, and have a long-term strategy to grow. We believe that we are on the right track in both of our core businesses, and we think this quarter's results support that conclusion.

We are optimistic about 2011, $90 oil is driving a shift towards more drilling in high liquids and oily areas. Issues in the Gulf of Mexico are redirecting exploration and development budgets back to safer environments like US Land. International events highlight the significance of domestic energy resources. And improved efficiencies, particularly in the shale plays are reshaping the natural gas industry in North America. We believe all of these things are positive developments for Patterson-UTI, and we are looking forward to a strong year. In closing this morning, I am pleased to announce today that the Company declared a quarterly cash dividend on its common stock of $0.05, to be paid on March 30, 2011 to holders of record as of March 15, 2011.

In closing, I want to thank all of our employees. Thank you. At this point, we would like to open the call for questions.

Thank you. (Operator Instructions). Your first question comes from the line of Jim Rollyson of Raymond James. You may proceed.

Good morning, guys. Great work.

Thank you.

Mark or Doug on the pressure pumping side, couple of things, one clarification on the 204,000 horsepower is that including the 50 you had previously under order, or is this all incremental? I couldn't remember exactly on the math.

Jim, it is not all incremental, some of this was ordered for Universal, what the 204,000 is all of the incremental horsepower we will add in 2011.

Okay.

It does include some things that we had previously told you were on order.

Got you. And from a margin standpoint, maybe a little bit of color, you mentioned the seasonal weather factors, which I assume is going to also maybe show up in the first quarter, given what is going on right now. But maybe a little color on kind of how the key equipment is performing, relative to your legacy, Patterson Universal stuff?

I think Jim, what I would answer that, it has certainly I think exceeded our expectations slightly. And I think, you have got to remember, this was really only one quarter we have had this equipment. But what I would say so far, we were pleased with both the revenue growth and the margin improvements that we saw with the equipment we bought.

And with regard to term contracts, you mentioned a little bit of progress there in South Texas, as well as up in Appalachia. Kind of where do you stand overall, and where do you think that goes over the course of the next several months? Do you just see a lot of customers wanting to sign some of this stuff up on term, or it kind of just hit or miss?

Jim, these are the first two, what I would call, contracts that we have signed. We do see further interest from our customer base. I think this whole industry has moved from, people used to call these contracts. They really were nothing more than pricing agreements. These contracts we have signed are actually much more like a term contract we would expect to see in the drilling business, I think there will be continued movement in this direction. Primarily because the operators are looking for dedicated frac crews, and want to have some assurance as to their future pricing.

Great. And then just one last one on the term contracts on the land rig side, you mentioned signing up 24, I think was the number in the fourth quarter, only four of those are new builds, maybe some color on the types of rigs of the other 20? Are these mostly upgraded older rigs, or some of the new builds that came out a little while back, or just kind of what you are seeing, and what the opportunity is for more?

Jim, it is a little bit of a combination of all of those things. I don't have the exact numbers in front of me. Some of it was some of our first Apex rigs that came out that were rolling over. But I think what I would like to say, there is a significant number of that 24, which are high horsepower mechanical rigs fit for purpose, for markets like the Bakken and say the Niobrara and the Mid-Con, that we were delighted to get term contracts on that type of equipment.

Great. Thanks, guys. Good.

Your next question comes from the line of Kurt Hallead of RBC Capital Markets, you may proceed.

Hey, good morning.

Morning Kurt.

Morning Kurt.

So I wanted to continue on the line of questioning from what Jim started here. So you referenced you got 86 I believe of your land rigs that are on contract for 2011. With respect to your frac capacity, what percentage of your frac capacity will be on a long-term contract in 2011?

Kurt, I am not sure any of us has got that number here at this point. Doug?

Yes, I could give you a guess, Kurt. I am guessing it will be, we are working on some things right now. I am guessing it will be somewhere between 70,000 and 100,000 of our horsepower will be under contract. It could be higher than that.

Okay. And you gave some guide points for the first quarter progression on land drilling. How about the progression on pressure pumping into the first quarter?

John? We think we put it forward, and we are looking back.

Yes, I didn't pick up on it, so I don't know if revenues will be up sequentially, or if they are going to be down because of seasonality. Jim had referenced the seasonality going in to the first quarter, that is a pretty astute observation given what is going on, but I didn't remember you guys talking about any specific directional guide points as you did with land?

Yes, I think in terms of pressure pumping revenue we expect to continue to increase somewhere in the $170 million to $180 million range.

Okay. And then the margins would move up commensurate with that?

I think they might move up slightly.

Okay.

I don't think a lot.

Okay. And then on the CapEx program, $900 million to obviously address the opportunity set that you have out in front of you. How do you plan on funding that CapEx? Do you think you will be able to do that through internal cash flow, or are you going to have to tap into the revolver or otherwise to make that happen?

I don't think we would have significant additional borrowings based on our view of how 2011 will roll out, assuming there aren't further acquisitions, or things like that. We may have a small amount of borrowings on the line at the end of the year.

Okay. And then you mentioned delivery times, so what are the delivery times now? So if you wanted to get a frac spread, and you went into your suppliers today, what would they tell you?

I think, Kurt, you are look at greater than six months, less than a year, and it depends on the specific piece of equipment that you are talking about. But I think on average, if you said today nine to 12 months, you are probably pretty realistic.

What is the bottleneck? Is it the engines themselves, is it the fluid ins, what seems to be the bottleneck?

It seems to change every week. Kurt it is really hard to answer that, but it is probably between pumps, transmissions, those are probably the two things. We are expecting the big engine manufacturers to be able to gear up and meet the demand. Pumps and transmissions can be a problem sometimes. Like I say it is something you have to manage the supply chain very, very carefully.

Okay. And last thing, Mark you mentioned a transformation of the Company over the course of the past 12 months, if not a little bit longer. We have done our math correctly here, it looks like Patterson is going to be adding 25 new-build rigs in 2011. I think that compares to about 14 or 15 for your two closest competitors. Looks like you are gaining a disproportionate share of the market? I am not quite sure if investors are aware of that. What is your sense in recent conversations with investors, are they aware you are gaining this share, or is it still a new story for most?

Kurt, I think that we have worked hard to try to get our message to the investment community that Patterson has been transformed, and it is not the Company that it was, say five years ago. I guess I think that that is one of those questions that is really hard for a Company to really assess how much the marketplace has understood that change. We occasionally get questions from people whose questions makes you think they haven't recognized it. So it is hard to really know the amount to which that message has gotten through, but we keep speaking about it.

Okay. That is it. Thank you.

Thanks, Kurt.

Your next question comes from the line of Scott Gruber of Bernstein. You may proceed.

Good morning gentlemen. Congratulations a great quarter.

Thank you.

What level of cost inflation are you currently seeing in pumping, if you look at labor, sand, additives? What is the general rate?

Well, Scott, I think we have seen some pressure on labor in certain hot markets. You can probably figure out which markets those are. I don't think we have seen any huge amounts of cost increases on input materials like sand, gel, we watch these things all of the time. Supply seems to be more of an issue than sort of cost inflation. But I would say, probably the biggest impact we are seeing in most of these hot markets is really the pressure on labor, and it is hard to really quantify that, because they are moving targets, but we have seen some sort of 5% to 10% labor pressure in several markets.

And remind me the general percentage of your cost base that is labor in pumping?

In pumping? Boy that is hard to give you that, because so many of these contracts either include sand, some don't. But if you look at our direct equipment and labor costs, boy Scott, we may have to get back to you on that. Because it varies so much. Obviously a 40,000 horsepower job the labor component is significantly higher than a 10,000 horsepower job.

Okay. That is fair. We can follow up. And then in terms of sand, there has been discussion surrounding potential tightness in that market. Are you comfortable with your access to sand going forward as you grow the fleet?

Well, we hope we are. We have done a lot of work, it is trying to make sure that we have got the right kinds of sand, and in the right areas. We do feel that we have got the supply chain somewhat nailed down. Of course, our customers sometimes change grades and types of sands that they want to use, so it is a little bit of, you are always making educated guesses on what you need and where you need it. There is no question that those sorts of things, I think over the next number of years as the industry tightens up, are going to be more and more important. And without divulging our own plans in this area, we watch those things very carefully and work very hard to make sure that we have got those things in line with what we project we are going to need.

Okay. And then just looking at your legacy Patterson fleet, where you do have an operational history, what is your average maintenance downtime today?

Oh, specifically just on the legacy fleets?

Well your fleet excluding the acquired Key assets, where I am sure you are still assessing the operational performance?

Oh, I am sorry, you are talking about pressure pumping?

Yes. Yes. What percentages of time are the spreads down to replace the fluid ins or the power systems?

Well again, that isn't a number that we necessarily track by total utilization, but it would be a very low amount of time. Let me give you this example,Over Christmas when the operators decided that they wanted to shut down in the Northeast, we took the opportunity to go ahead and do some of that repair and maintenance time then. So I wouldn't really call it downtime.

And let me say this, Scott, one of the things that our operations, both in the Northeast as well as in Texas pride themselves on, is that they maintain the equipment in good working order, and have in effect preventative maintenance, so as to assure that we don't have service interruptions for our customers, or unexpected service interruptions. We think we have been very proactive in both areas in respect of managing the equipment for sort of enhanced performance, and understand that that may be a slight competitive advantage.

Great.

Scott, the other thing that happens here when you are not operating on a 24-hour day, full 24 hours a day, quite often we may pump until midnight, and then we shut down until daylight comes, and typically what happens is the fluid ins and a lot of that routine maintenance are done in that period when the operator is not pumping.

Okay. That makes sense, and then in terms of the new pumps coming in, do you expect those units to be more robust in terms of the fluid ins, and the power systems being able to last longer as they execute these high flow rate jobs?

I think the simple answer to that is yes. I am not going to divulge to you what we have done differently, but obviously we have tried to learn from some of the experiences we have had over the last year or so, and there is no question that we are looking at different metallurgy, and different fluid ins, that we think will allow us longer operating hours on the equipment. So I think in general, the answer to that question is yes.

Okay. Thanks for the color. I will turn it back.

Your next question comes from the line of Robin Shoemaker of Citigroup. You may proceed.

Thanks. Doug, I wanted to ask, you mentioned 205 rigs would probably be the average for the quarter versus 194 last quarter. Is this coming from adding new builds to the fleet, or reactivation of older rigs, or both?

Well, it is a combination of both, coupled with the fact that we expect Canada to decline, so it is a combination of new builds, additional rigs, additional sort of legacy rigs going back to work in the fleet, so there is some sort of offset with Canada as well, Robin.

Canada is adding to the numbers in this quarter, but will decline toward the end of the quarter.

Yes.

So it is robust right now, but it will trail off as we think, in March.

Okay. Well, could you speak generally to the issue about the costs of reactivating the conventional rigs? I noticed you had an increase of $500 or so in rig-operating costs from the fourth to the first quarter, and what does that reflect? Rig reactivation cost part of the equation?

It wouldn't be significant Robin. I think we have bottomed out, I don't know somewhere 50 rigs in 2009, and we have gone up to a couple hundred of rigs running. So we have been reactivating rigs over the last 18 months. I think if you look, our cost per day has been generally relatively stable, as was mentioned in the opening remarks, we have had some labor increases, and that is a meaningful part of the increase in costs per day for the fourth quarter. Frankly, we try to keep, the rigs stacked in reasonable repair, whereby they are not meaningful costs to bring them back to work. I don't think that we could tell you just what the costs have been over those 18 months for reactivations, but I think if you look at the average cost per day, it has not been significant.

Sure. Okay. And then just last question on a lot of the E&P companies are talking about the very long horizontal laterals, going out to 10,000 to 12,000 feet, which looks to be a phenomenon that is going to continue, and perhaps over some period of time may become kind of a new norm. So in terms of, are your rigs drilling some of these extremely long horizontal laterals? And what do you think it means for both the upgrade, I mean the continuous addition of rigs to your fleet, and of course, I guess from the pressure pumping standpoint, it can only be additional upside?

Right. Robin this is Doug. There is no question that if you looked at our fleet today, and if you looked at all of the shale plays, we probably have 120 rigs working in those shale plays today. We have drilled some of the longest laterals that have ever been drilled in the Marcellus. Almost every one of those shale plays. The longer they get, I think it has certainly moved towards the 1,500 horsepower rigs. Every one of our new Apex rigs is highly capable of drilling those long laterals. Again, if you look at most of the new builds that we are adding to the market, that is what they are specifically targeted for. So we think we are in very good shape in terms of when you look at the rig count today, and see how many of our rigs are working in those shale plays, I think we have as many rigs working in the shale plays as any of our competitors.

Okay. Great. Thank you.

Your next question comes from the line of Joe Hill of Tudor Pickering. You may proceed.

Good morning.

Good morning, Joe.

An interesting point got raised by one of your peers the other day, and that is this rebound so far hasn't really seen a massive surge in new builds, in spite of the fact that operators are preferring newer equipment and different speced equipment, and I was wondering what your thoughts were on that, just the discipline of the industry in general, and whether or not that would hold up going forward, and whether or not just, you guys have gotten bigger in frac, Neighbors is obviously there now, just the paybacks in frac being attractive enough to soak up capital that might otherwise have gone to new rigs?

Joe, this is Mark. My sense of our industry, and I have obviously been watching it for the past 15+ years, is that we have been pretty financially disciplined as an industry, and we have responded to in effect the changing nature of drilling and well stimulation by in effect adding the kids of assets that the customers require, but doing so in a pretty measured way. And it is one of the things I find attractive about both the drilling business as well as the stimulation business. They both seem to have shown remarkable discipline, and especially remarkable considering the overall oil service industry.

Okay. Okay. And then Doug, what is your comfort level with term contract exposure and pressure pumping? It looks like you are anticipating something around 15% coverage right now. How high would you be willing to take that?

Joe we haven't really got a number in mind. I presume if we can get the right kind of returns in that business, I don't think we would have a problem taking that number significantly higher. It is all a balance about return to our shareholders, and how long the customer is really willing to commit to a crew. We look at it just like the drilling business. If we can meet our minimum hurdle rates for returns, we certainly are willing to contract more of the new equipment, and would consider adding more equipment on that basis.

Okay. And just finally, if I could some housekeeping items for John. The end of year debt position, and maybe the outlook for G&A, DD&A, interest and tax?

Yes, end of year debt as I indicated earlier I would not, based on how we see the world right now, would not expect to be significantly borrowing, barring an acquisition, or something like that.

I am sorry, John for 2010?

Oh, where we ended up on debt in 2010?

Yes.

That we ended up with no debt at all. No line of credit debt, just the long-term debt that occurred as a result of the acquisitions, and that is a total of $400 million.

Okay. Thanks.

Sorry.

And then for the other items for 2011?

In terms of 2011, I think the tax rate we are estimating right now is 37.5%. As you may notice, the rate was a bit higher in the fourth quarter than earlier in the year. And that is driven by a combination of factors related to some of the new tax law changes that were announced.

Basically with our large CapEx program for tax purposes, we find ourselves in a net operating loss position, which from a cash flow perspective is pretty darn positive, because we are able to carry back against years in which we had substantial tax payments, and I expect in 2011, from tax NOL, that we will get something north of $50 million of additional cash back presumably before July 1st, it could be somewhere in the $50 million to maybe the $75 million dollar range of cash flow from that source. But the effect of all of that is to have a higher effective rate in the fourth quarter, due to the carry back we lose some of the benefits that we got from some of the deductions that were in place in those earlier years. The tax rate going up a little bit from what it had been earlier this year, for 2011 37.5% is driven by that same phenomenon.

In terms of G&A, I would expect to be in the first quarter similar to what we saw in the fourth, which was net 15 to 15.5 type of range. Depreciation currently guesstimate somewhere around $100 million for that. One other housekeeping item I would like to make clear, we have kind of bounced around it, but just to be as clear as I can be on it, just a reminder I think we provide you guys every year on our fourth quarter call, and that is that our presence in Canada has a very meaningful seasonal aspect to it. Right now that rig count is very high, very strong, very profitable.

As we go into March, that rig count will decline depending on when things thaw out, and in the second quarter, we would not expect to average many rigs at all. It could be, probably two or three is about as good as you do. That is when they shut things down, and do all of their repair and maintenance, and wait for the land to dry out a little bit. So when you look at first to second quarter even with new rigs coming out, and some number of existing rigs that are not new builds, the rig count from first to second quarter would likely not move up, and in fact could drop a few given the seasonal impact of Canada.

Alright. Okay. Good quarter. Thanks, guys.

Your next question comes from the line of Dave Wilson of Howard Weil. You may proceed.

Good morning, gentlemen. Just real quickly, Doug, you had mentioned that the first half of the year, your rig slots were pretty well full, and about how many could you add if you got the orders today during the second half of the year? How much capacity do you have to add more rigs during the second half of the year?

Dave, that is probably a very limited amount. I would hate to give you a number, but if that stuff isn't on order today, you would probably be hard pressed to get it out in 2011.

Dave just to be very clear, what was said was that our new-build rigs are taken up from, in effect for the first half of the year, there are new builds on order that are available for contracting in the second half. But we have other rigs in our fleet available right now, and would welcome any customer who would like to call.

Okay. Thanks for clearing that up. But just I guess on a run rate, I mean looking out to 2012, about how many rigs could you add, have the capacity to add in any given year?

Oh, I think if you look back at the year 2008, just the quarterly stuff out there, you will see that we added 60 rigs to the active count in about six months. Our ability to activate rigs is significant. Granted there are many challenges like hiring the people. You do have to have arrangements to be stacked, or make it field ready. But our ability to activate rigs is significant.

Dave, were you specifically asking about new builds?

Yes, I am sorry, I was asking more on the new-build side?

We built 19 this year, with a number of other rigs in various stages of completion. We expect to finish 25 this year. I believe our capacity is probably somewhere between two and three rigs a month. Now if we see demand further than that, can we add capacity to that? Yes, we can, we have the capability. But I think today we are at a capacity that a couple a months is, we are quite comfortable with. But to go much beyond that we are going to have to add people, and certainly have those items in the supply chain coming in.

Okay. Thank you very much for the clarification on that, guys.

Your next question comes from the line of Geoff Kieburtz of Weeden & Co. You may proceed.

Good morning.

Hey, Geoff.

How are you?

Good.

Couple of quick ones. On your pressure pumping fleet, and it may be more meaningful to talk about this Texas versus Appalachia, but what percentage of your fleet is work 24/7 now?

Geoff it is very unusual for it to happen in the Appalachians. So I would say virtually none of it up there is 24/7. Down here we have probably 25% of our fleet working 24/7.

Okay.

There is a move, there are certainly a number of customers that are trying to move in that direction. And it is certainly one way that you get your utilization up higher. But there are some challenges in that business, that I don't think it is something that we can force.

Right.

Just because of the nature of the jobs, and people typically don't particularly like to do it at night.

Right.

But certainly people are moving towards much longer days than we ever have in the past.

Okay. Then on the drilling side, the margin guidance for the first quarter, about half of the rate of increase that you have posted in the fourth quarter, is that just being conservative? Are you seeing some reason to expect a deceleration in your margin expansion?

Actually, Geoff, the thoughts we have is for kind of a $900 kind of increase in revenue.

Okay.

What is affecting it though, is as we spoke about before some increases in wages potentially driving up costs. Also some costs that are unique to first quarter, with payroll taxes and the like, so there are a few of those kinds of issues, so that in effect our margin growth expectation is good, but not spectacular in the first quarter, owing to those two things.

Right. And could you remind us approximately what that first quarter payroll tax impact is?

Oh, it is probably $75 a day.

Okay.

It is not a real big impact, but it is some in our case. The other thing to point out, Geoff, as you look at the fourth quarter increase, that was Canada, I think you can tell from the press release table, Canada had a meaningful impact on that.

Okay.

And will continue to have a meaningful impact on having high margins for the first couple of months of winter, the first quarter, and then it kind of flips the other way sometime in March.

Right.

So that is also a consideration when we look at our margins fourth and first quarter.

Right. And just to be clear, has there been any change in your ability to pass-through your wage increases?

No, we continue to pass them through.

Right. And then kind of big-picture question, you I think in your closing remarks, Mark, made the comment that you see great investment opportunities in both of your businesses. Most of the conversation has been about organic investment. Do you see as well acquisition investment opportunities?

Geoff it is interesting you asked that question, because it seemed as if for a couple of years we spent a lot of time sort of trying to respond to the fact that we hadn't done an acquisition for a while. Last year was a pretty busy year for us on both the acquisition and divestiture front.

Okay.

I am sort of pushing the wireline transaction, which got completed just a week or so ago, into last year, because it was part of the overall plans of what we did. So we had a very busy year on the acquisition/divestiture front, one which we were obviously quite pleased with. We are continuing to try to see the opportunities in those industries. We think that there are some additional opportunities. We look for them. But quite frankly the point I guess we are trying to make is that the organic internal growth opportunities that we see are so attractive, that we are happy to focus on that subject, of course, to waiting for and seeing whether we can uncover something really phenomenal.

Okay. Great. Thank you very much.

Your next question comes from the line of Arun Jayaram, Credit Suisse. You may proceed.

Good morning, gentlemen.

Hi Arun.

Doug I was wondering if you could comment, as you bring the additions of additional horsepower into the marketplace in 2011, help us think about what this could mean to your margins? And also I would like to maybe get a sense of in what markets are you putting them in at that incremental capacity, or plan to put that capacity in to?

Arun let me answer the second question first. The 204,000 horsepower,our plans today look like a pretty even split between the two markets. But I will say this, as things change, as we see customers willing to commit under contracts that could change, but if you asked us today, we would say we think it is pretty close to a 50/50 split as to the two markets it could go into. But keep in mind if somebody is willing to sign a long-term commitment in one or the other of those markets, we reserve the right to change our minds as to where it is going. Your second question was more related to how do we see the impact of the new equipment?

To your margins?

Yes, I think it is obviously, I think it has got some positive spin on our margins. I think all of this new equipment, if we can contract it with customers, and at the rates that we think are indicative in the marketplace today, I think it will be very positive for our margins.

Sounds good. And Doug could you comment a little bit, you have had a about maybe three or four months of history now with the Key assets. What are you doing to put the Patterson stamp on these assets? Do you think there are some opportunities for further pricing, to take some costs out? I am just trying to get a sense of what self-help you could put to those assets?

Arun, let me try to answer that. We think we acquired a business with excellent management. So the first thing we would like to do is acknowledge that the people and the business that was acquired was doing a good job, and we didn't feel that it was one of those businesses where you buy it and say, oh I am going to fix it. It was a good business. One of the things that obviously is different from our perspective is that for Key it was a decision on their part to divest, because it wasn't core to what they were trying to do. Obviously from our perspective, it is core and right in our middle fairway, so to speak. I think the difference that is that we are focusing on it, and able to commit capital to it, and do other things, which all of which I think collectively I think helps.

We think also both the drilling business and the well stimulation, the pressure pumping business, we share similar, we share the same customers. There are a lot of things where there are cross-over benefits, we think from marketing and other relational perspectives. So I think we feel that we are able to help that business, perhaps get some more out of it, owing to relationships, owing to some marketing things, and owing to the fact that it is part of our core businesses. But I want to make it clear that we think we bought a very good company with very good people.

And last question, Mark you talked about a lot of large international majors coming to the marketplace. Could you talk about opportunities to expand the customer list? And what you are seeing, what is Patterson doing to take advantage of all of this capital that is coming into North America?

I would just say to you that we obviously recognized that the customer base in North America has been changing over the past several years with this foreign-direct investment that is coming. We have thought about, and understand that change, and have strategic plans that take into account those facts. And target the appropriate customers to try to do business with them, and try to build appropriate relationships with them.

Fair enough. Thank you.

Your next question comes from the line of David Smith of Johnson Rice. You may proceed.

Thanks guys fitting me in. Can you please walk me through the CapEx expectations out of the $900 million for the year, you mentioned $220 million on the pressure pumping. Can you help me with the rest of that split, please?

The vast majority of the rest goes to drilling. I'm not sure, John --

How about how that breaks out between the Apex rigs, and maybe any other upgrades you were planning?

In terms of new capacity, and realize the building of rigs and other equipment doesn't really exactly fall in the year, it is an ongoing program. So you have some that was already spent last year, relative to rigs you are building this year, and things of that nature, but in terms of new drilling rigs, dollars spent in 2011 is expected to be somewhere $375 million or so. And there is also substantial rig upgrades in the neighborhood of somewhere, $150 million to $175 million. There is another $125 million or so of what we classify as maintenance CapEx. Some of that we have found that per day we run a rig, our costs of rebuilding engines and different parts of the rig, averages $800 to $1,000 a day. For internal purposes we use $1,000 a day for that. We are also, we call it maintenance capital, but we also add to our trucking fleet at times, and replace drill pipe and other things. So between all of that would give you the drilling component.

That was very helpful, thank you. On the rig upgrades how does that compare to what you did in 2010?

It would be about half.

Yes, I think that's probably--actually at the end of the day, I think it is actually pretty similar.

Is there a way to tie that back to number of rigs that could impact, or is that just too spread out between what type of drives, mud pump upgrades, et cetera?

I think it's--

I will follow back up on that one.

Yes, it is a difficult thing because we plan for a certain number of refurbs, but as we get into this thing, the market changed, customer demands change. It never looks exactly like what we planned. So it is hard to give you our plans today, because I can assure you it will be very different by the end of the year.

Within that there is some top drives, a few refurbs.

Great. Thank you very much for the color. Great quarter. And I look forward to next.

Thanks.

Your next question comes from the line of Judson Bailey of Jefferies and Company, you may proceed.

Thanks. Good morning, guys. A couple of questions on the rig side. You have done a great job growing the rig fleet over the last year or so. As you look forward, I am curious if all of the various basins, between the Bakken and the Marcellus and the Permian, where you are very active, where do things still seem to be the tightest, where are you seeing the most incremental demand at this point? And could you maybe talk a little bit about the types of customers you are seeing, you are getting the most calls from now?

Jud, that is kind of hard to answer that question. I mean I think the Bakken and the Niobrara are probably two of the areas today that still looks like there is incremental demand.

And the Permian.

Yes, certainly and the Permian. I think a lot of the other areas have, there still seems to be some demand by certain customers, but every one of these markets seems to evolve. I remember sitting here a year ago, and we were all talking about the Haynesville, and how big that was going to grow, and where were the rigs going to come from, and here we are a year later that there are a lot of rigs have moved out of the Haynesville and moved to the Eagle Ford. So I would say just to generally answer your question,West Texas, the Eagle Ford, the Bakken and the Niobrara are probably the markets today that we get the most calls on.

Okay. That is helpful. And in the Permian what kind of rigs are they wanting? Are they wanting the mechanical ones, or do you see more of a desire for some of the higher end rigs?

It kind of goes across the whole spectrum, we have got demand for the kind of lowest, oldest rigs in our fleet to the newest, most advanced rigs. It is across the board.

And the pricing environment there for those, are you seeing some upward movement still?

West Texas is the new hot market as people have written, and it is entertaining from perspectives of people who have been in the market for a long time to see get referred to as the new hot market, but I can tell you that the shortages of people in that market are, it is one of the most acute markets for shortages of people.

Interesting. And one last one, just Canada. I know it is small, but you touched on it some already. The rates were pretty good in the fourth quarter. I would imagine they will be good again in the first. Do you have any insight at all for the back half of the year? I know it is going to depend on break up and that sort of thing, and recovering from that. But you seem to have gotten a nice bump in rates there. Is there anything in particular driving that, I guess?

Really just driven by the best demand we have seen there in several years, and we don't have any visibility beyond breakup.

Okay.

The one thing I would add to Canada is we have added some top drives to a number of rigs in that marketplace, and are getting paid accordingly for them. And I think you will see demand for top drives in that market continue to increase over time. But I think the way that year is unfolding it is fairly typical that you get your best rates and margins sort of in the winter drilling season as demand is high, and as think the rig count falls off, there is much more pressure on prices in the summer and fall.

Sure. Okay. That is helpful. Thank you. Good luck.

Your next question comes from the line of Ole Slorer of Morgan Stanley. You may proceed.

Thank you very much for fitting me in there. Good quarter by the way.

Thank you.

And good outlook too for that matter. Just some clarification to help us understand the capacity to put rigs back to work for the industry as a whole, it looks to me as if you have about 10% market share at the moment in the North American land market, and you are adding new builds faster than anybody else, and if you live under the assumption, which I think is a fair one, that we will continue to live in a rig-constrained market for quite a while looking forward, and you add your 25 rigs. You have competitors adding some rigs, 60 to 55, maybe there are another 15 or 20 rigs that will be added by people outside of the big three, would that be a fair number do you think?

We can subscribe to just what we see public announcements for. In respect to the others, we read the same analysts reports that others put out, and I mean, nothing you have said is inconsistent with what we believe, frankly, except I guess we would think our own market share is perhaps slightly higher than the 10% number you gave.

I just used the Baker Hughes 1,700 rigs, and you have 170 working in the US or thereabouts, so--

We won't quibble.

Yes, that is the matter of definition. But broadly then. So if we look forward for the next 12 months, maybe assume that there is maybe 55, 65, 70 new builds or something like that, that clearly will be absorbed into the market, what do you think the capacity is for additional refurbished rigs to be made available, that are of a quality such that the operators will likely want to use them in these new complex deeper and directional environments?

The thing that I think was most interesting to us about fourth quarter was the number of term contracts that we were asked to sign by customers for non-new rigs. Which tells you that from the customer's perspective, these rigs are highly desirable. We think that we have a pretty good fleet of those kinds of rigs, which gives us an opportunity to actually put more rigs to work, over and above the in effect new rigs, and kind of maybe as a slight competitive advantage. So this is kind of an opportunity for us. Now how many more rigs go to work during the rest of the year, frankly is something that we can't really project, unless you can tell us exactly what is going to happen to commodity prices.

Does it seem that the demand for oil rigs that will be made available that are of a decent quality, under that scenario, how many rigs do you think that you think you would be able to put, excluding new builds, how many new rigs other than new builds do you think you would be able to offer to your customers?

Yes, I think it is all matter of what they are looking to drill for.

Deep formation, or deeper formation and long horizontals.

I think the industry in total only has probably very little capacity for say 1,500-plus horsepower rigs capable of drilling the kind of wells you are talking about. To put this in perspective, I think a year ago, probably less than 5% of the wells drilled in the Permian were horizontal. I think that number today is up to about 15%. If you see the Permian, for example, move in the same direction as Eagle Ford, Niobrara, the Bakken, I think there are probably very few rigs in that marketplace that are actually capable of doing that without a significant amount of capital spent on the rigs to do the kinds of things that the operators want to do. So I think most of that demand is either going to have to come from new builds, or the industry spending a lot of money on refurbishing existing rigs.

Yes, that is kind of my conclusion. So on that scenario in terms of what really drives pressure pumping, in other words, this is one of the things I am getting at is really scoped to grow the overall fleet of land rigs of that type of a quality by more than 70, 80, 90 rigs this year, from where we stand now?

I think the industry would have a very difficult time doing that in this timeframe. Because like I say, if you don't have the things in the pipeline and on order today, you are not going to be able to add it very quickly.

How do you see the pressure pumping dynamic then, relative to the outlook for quality land rigs? Given I mean, if my numbers are correct, compared to the last conference call, you just doubled your horsepower, are underlevered for 2011. I might be wrong, but it looks like you did that. And we are seeing similar moves from a lot of other people, and of course the market is very undersupplied at the moment, there is no doubt about that. But how do you see the dynamic play out between the bottleneck of horsepower, relative to the bottleneck of high-end land rigs?

That is kind of why we started out by putting in our script those three points that we made reference to about the service intensity, number of stages, and required horsepower.

Absolutely, yes.

And number two the fact that the equipment is wearing out at a faster rate than historically has been seen. And three, the highly restricted supply chain already. What we think is the industry is playing catch-up in 2011, and we don't see that catch-up as being kind of accomplished this year.

Yes.

So frankly when you speak about what is going to happen with respect to the new rigs being built, and how many new rigs are out, and so on and so forth, we think the pressure pumping business is in a catch-up mode, and is likely to be in that mode for at least the next 12 months. We typically have not spoken out further than one quarter anyway.

No. We are all seeing the same trends and the same factors, and trying to make it all add up.

Yes.

But thank you very much. Thanks for your view on that, and good luck to you.

Thank you.

Your next question comes from the line of Tom Curran of Wells Fargo. You may proceed.

Operator we are going to take this call, and that is going to be the last call.

Good morning, guys, thanks for the privilege of squeezing me in last. Believe it or not, I still do have one remaining question here. Curious, what is your total maintenance CapEx budgeted for pressure pumping for 2011? And could you provide a breakout between legacy Patterson, Universal, and then the Key business?

No, on the second part. I think it is interesting, we don't really know maintenance capital and pressure pumping until the get into the year. It tends to show up when it shows up. We did some things six, eight months ago to try to estimate how much we spend on maintenance capital on those businesses, and our take was on a combined basis it was going to be somewhere $20 million or so. But by the nature of it, it does tend to show up when it does. Something breaks down, and you need to rebuild it. Drilling on a large rig fleet like ours, drilling we found it to be incredibly predictable, a little less so on the pressure pumping.

Tom, one of the things that is so different about the pressure pumping business today, we don't have a long history of how quickly we are wearing out the equipment, so we have some numbers, but I would hesitate to throw them at you. This whole phenomena about this high-pressure, multi-stages, working the equipment 24/7, we just haven't had enough history to really know what the costs are. Now we are watching this very closely, and every quarter we kind of try and get a little better handle on it. But for us to kind of give you a definitive answer today, I am not sure would be very helpful to you.

Okay. That $20 million estimate, was that for both businesses combined?

Yes.

Okay. And do you happen to recall what it was for just Universal in 2010 or 2009?

It would be about half of that.

Okay.

Half of the numbers.

Okay. Alright. That is all I have. Thanks for taking the extra time, guys. I appreciate. .

You bet. I would like to thing everybody for your participation in our call. I look forward to speaking to you at the end of our first quarter. Thank you.

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Have a great day.