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Patterson-UTI Energy, Inc. (NASDAQ:PTEN)

Q4 2011 Earnings Conference Call

February 2, 2012 10:00 AM ET

Executives

Mike Drickamer – Director of Investor Relations

Mark Siegel – Chairman of the Board and Director

Doug Wall – President and Chief Executive Officer

Analysts

Jim Rollyson – Raymond James

Joe Hill – Tudor, Pickering, Holt & Co

Dave Wilson – Howard Weil

Scott Gruber – Sanford Bernstein

John Daniel – Simmons and Company

Justin Sander – RBC Capital Markets

Luke Lemoine – Capital One

Andrea Sharkey – Gabelli & Company

John Tademir – Canaccord Genuity

Waqar Syed – Goldman Sachs

Operator

Good day ladies and gentlemen and welcome to the fourth quarter 2011 Patterson-UTI Energy Incorporated conference call. My name is Jena and I will be your coordinator for today. At this time all participants are in listen-only mode. We will be facilitating a question and answer session towards the end of today’s conference. (Operator Instructions)

As a reminder this conference is being recorded for replay purposes.

I would now like to turn the presentation over to your host for us today Mr. Mike Drickamer, Director of Investor Relations. Please go ahead.

Mike Drickamer

Thank you, Jena. Good morning all in behalf of Patterson-UTI Energy. I would like to welcome you to today’s conference call to discuss the results of the three and twelve months ended December 31, 2011. 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, will state the company's or management's intentions, beliefs, expectations or predictions for the future, are forward-looking statements. It's important to note that actual results could differ materially from those discussed in such forward-looking statements. Important factors that could cause actual results to differ materially include, but are not limited to, deterioration of global economic conditions; declines in customer spending, prices that could adversely affect demand for the company's services and their associated effect on rates, utilization, margins and planned capital expenditures; excess availability of land drilling rigs and pressure pumping equipment, including as a result of reactivation or construction; adverse industry conditions; adverse credit and equity market conditions; difficulty in integrating acquisitions; shortages of labor, equipment supplies and material supplier issues; weather, loss of key customers, liabilities from operations, government regulation; 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 and through the SEC's EDGAR system. The company undertakes no obligation to publicly update or revise any forward-looking statements.

Statements made in this conference call include non-GAAP financial measures. The required reconciliations to GAAP financial measures are included on our website www.patenergy.com and in the company's press release issued prior to this conference call.

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

Mark Siegel

Mike, thank you. Good morning and welcome to Patterson-UTI’s conference call for fourth quarter 2011. We are pleased that you are able to join us today. As is customary, I will start by briefly reviewing the financial results for the quarter ended December 31 as well as for the full year 2011 and then I will turn the call over to Doug Wall, who will share some detailed comments on each segment's operational highlights for the quarter as well as our outlook. After Doug’s comments, I will share some closing remarks before turning the call over to questions.

As said forth in our earnings press release issued this morning we reported net income of $87.6 million or $0.56 per share for the fourth quarter ended December 31, 2011 and $322 million or $2.06 per share for the full year 2011. EBITDA for the quarter improved to $272 million marking the 10th consecutive quarter of EBITDA growth.

The financial results for the fourth quarter include a pretax impairment charge of $11.3 million or $0.05 per share related to the previously announced retirement of 31 drilling rigs. For the full year 2011 we retired a total of 53 drilling rigs as part of an ongoing process by which we evaluate each rig in our fleet. As a result, we incurred an impairment charge of $15.7 million or less than $300,000 per rig.

While we saw sequential growth in both of our core businesses, the growth was primarily attributed to the contract drilling segment. This segment, which accounts for approximately two thirds of our revenue benefited from increasing rig activity driven by continued strength in the oil and liquids rich plays. We have now witnessed through December 30 consecutive months of growth in our U.S. rig count that is starting in July 2009. And I’m very pleased to tell you that our rig count continued to increase in January.

Additionally, the contract drilling business benefited from cost control initiatives that were geared towards reducing the cost of negatively impacted our third quarter. These cost reductions combined with $370 per day increase in average revenue per day in the U.S. led to an increase of $770 in average rig margin per day in the U.S.

Although pressure pumping revenue grew by 7% in the quarter we were disappointed by our results in this segment. At the onset I want you relate that our southwest region performed strongly in the fourth quarter and is continuing to perform well in the first quarter. In the northeast however a variety of factors impacted our pressure pumping revenue growth including certain customer specific delays and less demand for short notice work later in the quarter.

The northeast pressure pumping market has remained soft since January but all crews are currently scheduled to be active by the end of the (Inaudible). In his remarks Dough will provide some additional details about this segment but I do want to add that we think we have seen a shift to greater seasonality in the pressure pumping business in the northeast as both customer and the local authorities in respect to roads I’m more vary of high activity levels during the most difficult winter weather.

Overall in 2011 we achieved growth in both contract drilling and pressure pumping reflected in a 75% increase in revenue and 176% increase in net income, which result from the investment we have made in both our people and our equipment. In total in the past two years we spent approximately $2 billion on equipment. This investment furthered the transformation in our company with the addition of 44 new Apex rigs and approximately 470,000 horse power of pressure pumping equipment.

In 2012, we expect to spend approximately $1.1 billion on CapEx, which includes the construction of 39 new Apex rigs and 140,000 horsepower our pressure pumping equipment. We expect to fund this capital spending largely through internally generated cash flow. Considering this level of Apex for 2012 we expect depreciation expense for the full year 2012 to be approximately $520 million.

Before I turn the call over to Doug, I want to address concerns about low natural gas prices at this point in the year. We like everyone involved in the North American energy industry, appreciate concerns hid in the past 30 days about stubbornly high production levels and the high low natural gas prices. From our perspective what we are seeing a continuing and pressure pumping equipment. Migrating from dry gas areas to oils and liquids rich areas. The relative strength in these oil and liquids rich regions has absorbed at least for Patterson-UTI. Rigs that have been released from dry gas markets and we expect this will continue this year.

Moreover, in pressure pumping, the majority of our fracturing horse power is located in oil and liquids rich areas. In addition, 30% of our fractured horse power is undertake or pay contracts. Finally, term contracts and equipment quality should mitigate a significant amount of the risk for the Patterson-UTI arising from downturn inactivity for dry gas and we see 2012 as being another strong year for the company.

I will now turn the call over to Doug.

Doug Wall

Thanks Mark. I will start this morning with some commentary on the drilling company before turning to pressure pumping. Demand continue to remain strong for our drilling rigs during the fourth quarter as our average number of rigs operating in the U.S. increased sequentially by 11 to 220 rigs, while our Canadian rig count was relatively flat at 12 rigs.

The increase in the U.S. rig count was driven by the seven new Apex rigs completed during the quarter as well as the activation of additional conventional rigs. In total, we completed the construction of 25 new Apex rigs during 2011 and we remain on schedule to increase our production to complete 30 Apex rigs during 2012. We now have long-term contracts for 13 of the 30 Apex rigs that we plan to build during 2012 and see additional new build demand primarily in the oily market.

Despite the very recent weakness in natural gas prices demand for our rigs continues to be strong. We average 241 rigs during the month of January 225 in the U.S. and 16 in Canada. For the first quarter of 2012, we expect a further increase on our operating rig count to approximately 242 rigs including an average of 227 in the U.S. and 15 in Canada.

Let me address our exposure to the dry gas markets, which we think will be mitigated by a number of factors. First, we continue to see a migration of rigs from the major natural gas plays to the oilier and the high liquids plays and we expect this migration to continue. Secondly, approximately 60% of our rigs active today in the U.S. are committed under long- term contracts.

Although some of our competitors use a different standard, it’s important to note that we define a term contract as having initial duration of at least 12 months. Including only contracts already in place we expect to average at least 120 rigs under term contract in 2012 including an average of 131 during the first quarter. This 120 rigs under term contract is up 96 from our last conference call are up from 96 in our last conference call.

Finally, we estimate that roughly 60% of our rig fleet is drilling either oil or liquids rich wells. Our greatest exposure to dry gas is within our East Texas and Marcellus regions. In the Haynesville we currently have 23 rigs drilling for gas 12 of which are under term contract. While we expect that only a handful of the 11 rigs in the spot market will move to other markets primarily more focused on oil or liquids rich activity let me point out that all 11 of the spot rigs in this market are 1000 horsepower or greater and therefore we think they are in the sweet spot of demand for other markets such as the Permian, the Eagle Ford and Mid-Continent.

In Appalachians, which includes both the Marcellus and the (Inaudible) shale our term contract coverage is even stronger. 29 of the 34 rigs drilling in this market are currently under term contract just as important four of these are drilling in the liquids rich plays and another 15 are drilling in the more liquids rich targets in Southwest Pennsylvania. Of the remaining 15 rigs drilling in Northeast Pennsylvania only two are in the spot market. We are not expecting a meaningful decrease in our drilling activity in Appalachians given our low spot market exposure.

Overall we feel quite confident that our term contract position and the uptick of spot market rigs from the dry gas areas to the liquids rich plays will keep our activity levels below. Let me make a couple of quick comments on the revenue and cost side relating to the quarter. Average revenues per operating day for the fourth quarter were $21,980 a sequential improvement of $540 per day. Rig pricing continued to improve during the quarter and the impact of new build contracts help push our revenues higher.

Well we have some unusually high repair and maintenance cost during the third quarter I’m pleased to say that our average direct operating cost decreased by $280 per day to $12,700 for the fourth quarter. Direct operating cost in our U.S. land business are actually down $400 per day but the overall decrease is lower than this due to the normal winter cost increases we experienced in our Canadian business.

For the first quarter we anticipate an increase in the average revenue per day of approximately $350 partially offset by an expected increase of $200 per day in operating costs. While we are not prepared to speak to the second quarter in any detail please let me remind you that historically the second quarter has been impacted by the seasonal breakup in Canada. Historically we have averaged about two rigs in Canada during the second quarter.

Before I turn the discussion to pressure pumping let me make a few comments on the announcement regarding our retirement of the 31 rigs during the quarter bringing our total rig retirements for the year to a total of 53 rigs. In our fourth quarter rig assessment we determine an additional 31 rigs would no longer be marketed and they have now been retired. Certain parts of these rigs have ongoing value and the parts have been transferred to inventory to support our remaining rig fleet. Of the 31 rigs the average horsepower rating was 735 horsepower segment of the market where demand is the weakest.

Overall in our assessment we determined it made no sense to refurbish or spend any incremental capital son these smaller type rigs.

So turning now to the pressure pumping segment as Mark mentioned earlier the growth in this segment fell short of our expectations. Revenues for the quarter increased approximately 7% sequentially to $241 million. EBITDA for pressure pumping totaled some $72 million for the quarter up slightly from Q3. EBITDA for the full year in our pressure pumping business totaled some $267 million.

Late in the quarter, we began to see some utilization issues in the northeast market the quarter finished on a rather weak note as we were hit very hard by the Christmas and holiday shutdown. In addition, a number of our customers in the northeast had a combination of location issues well bore and other drilling issues and some operator provided water issues, which caused numerous delays and pushed a great deal of work into the first quarter. Unfortunately some of the above delays impacted our January activity as well.

The event of large horizontal tracks has fundamentally changed our business particularly in the Marcellus. For the second year in a row we have witnessed a slowdown in the fourth quarter and well into the first quarter as our customers continue to grapple with logistics issues related to completing these types of wells in the winter time.

In general, the in efficiencies and the higher cost brought on by the winter weather are creating a new seasonality effect in Northeast. In general, I believe it’s fair to say that the northeast market has changed considerably over the last couple of years. It appears the backlog of work waiting on completion has declined substantially providing fewer options for short notice work.

Having said all this, our customers are indicating increased demand late in the first quarter and all of our frat crews are scheduled to be active by the end of the first quarter in this market.

Turning to the southwest region our activity levels remain strong and while we do it but some addition equivalent to answer the southwest market we do expect the strength in this market will continue. Operating costs in both regions continue to increase and are pressuring our overall margins a pause for labor and materially and in particular sand and hydrochloric acid as well as logistics cost continue to weigh on our overall margins although we believe these costs will level off.

During the quarter our pressure pumping supply chain management did an outstanding job of avoiding many of the logistics issues that have impacted the industry. During the fourth quarter, we took delivery of $58,000 750,000 horsepower although I must say little or no impact on our revenues for the quarter as the deliveries occurred very near at the end of the year. It did however have an impact on our cost as we hire then train crews to run this equipment.

In total, we took delivery of approximately 200,000 horsepower during 2011 and ended the year at approximately 631,000 total horsepower in our fleet. During 2012, we expect to take delivery of an additional 140,000 horsepower all of which is expected to be delivered by the end of the third quarter.

We currently have 155,000 horsepower under take or pay term contracts. Roughly split evenly between our two markets. We do believe we will continue to see some equipment move from the dry gas market to meet the unsatisfied demand in the oilier base. Just as we did last summer in moving equipment out of the Barnett we will continue to move our equipment and our people to the markets where we can maximize utilization and generate higher returns.

With respect to the first quarter in our pressure pumping business, both revenues and margins continue to be impacted by the later slowdown and inefficiencies resulting from this lower utilization in the Northeast. We are expecting pressure pumping gross margin percentage will be about 30% for the first quarter while pressure pumping revenues are expected to be similar to the fourth quarter. We do expect a seasonal recovery in the second quarter.

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

Mark Siegel

Thanks Doug. As we conclude our prepared remarks, the message I would like to leave with shareholders, is that as a result of the transformation our company has undergone over the past several years, we believe we have sustainably lessened our exposure to cyclical downturns. Despite the slowdown natural gas related activity we are optimistic that 2012 will be a good year for the company.

Let me tell you why. First of all approximately 60% of our fleet is currently drilling oil or liquids rich wells. Second, and more importantly we have made significant investments in high grading the quality of our fleet. We ended 2011 with 91 Apex rigs in our fleet more than three times the number we had in our fleet three years ago. These investments have allowed us to significantly increase our term contract coverage as we currently have approximately 60% of our active rigs operating under term contract, almost three times the term contract coverage we had three years ago.

Finally, our pressure pumping fleet is about five times the size of what it was three years ago. More importantly our pressure pumping business has expanded geographically over this time period and substantially increased our exposure in this business to oil and liquids rich markets.

In short, we are positive in our outlook for 2012. If the industry remained strong in 2012 we think we are very well positioned to benefit. In our respect when we tell you we have the addition of 30 new Apex rigs in 2012, which will likely increase our average daily revenue. Second, with the strength of our balance sheet we can be financially opportunistic then continuing to grow the company or pursuing other options if our evaluations continues to remain depressed.

With that I would be remised if I did not thank the men and women of Patterson-UTI many of whom are on this call today. Your hard work combined with your focus on safety and customer service make this company strong a company we could be proud of. Operator, we would now like to open the call for questions.

Question-and-Answer Session

Operator

Thank you (Operator Instructions) and your first question comes from the line of Jim Rollyson with Raymond James. Please go ahead.

Jim Rollyson – Raymond James

Good morning guys.

Mark Siegel

Hey Jim.

Doug Wall

Hey Jim.

Jim Rollyson – Raymond James

Doug couple of questions I guess on the rate side. 30 new rigs this year on top of 25 last year and 140,000 of pressure pumping capacity, can you kind of give us some sense of what your schedule is for that delivery for this year?

Doug Wall

Jim it’s pretty evenly broke down but certainly on the rig side we are looking at really little in average of seven a quarter. It varies a little bit depending on customer requirements and when they are looking for the rigs but in terms of just giving you some guidance it’s pretty much evenly split through the year.

Jim Rollyson – Raymond James

Okay.

Doug Wall

And in my comments that on the frac horsepower it really is front end of the year loaded. We expect to have all that equipment delivered, put together and hopefully working early in the third quarter.

Jim Rollyson – Raymond James

Helpful. Last year and your kind of earlier comments before this quarter were also you were reactivating or refurbishing rigs at something like around one a month. Thoughts or plans for reactivations for 2012?

Doug Wall

Jim we really don’t see a whole lot of refurbishment of further rigs this year. We do expect there will be some reactivation through the year a lot of that really will depend on natural gas pricing. But we certainly have identified some limited number of rigs that if things still progress that we will consider reactivating and would require a minimal amount of capital to put back to work.

Jim Rollyson – Raymond James

Understood and.

Doug Wall

I don’t see the levels being as many as we did last year.

Jim Rollyson – Raymond James

Understood. On the retirement side of things you’ve retired a few rigs each of the last couple of two or three years. Anyway, you think you are mostly through rigs that are kind of under consideration for retirement at this point.

John Vollmer

This is John, ever quarter effectively they are evaluating the rig fleet I think it was roughly 50 last year the year before that I think we were four or five so it’s really dependent on the demand on the rigs and the state of rigs as time passes.

Jim Rollyson – Raymond James

Alright, and last question for me just kind of curious what your customer commentary has been about any possibility for the rig markets that you guys have exposure and maybe have contracts in like the Haynesville for example by your customers desire to relocate those elsewhere.

Mark Siegel

Jim, that’s been a fairly recent occurrence I guess with most of the markets that I think people are concerned about the customer seem to alternate from weak to weak as to what their plans are. To-date we have seen very little impact or even people getting serious about moving rigs from market to market. I would like to mention I would say in both of those markets that I think people refer to the most is Marcellus and Haynesville we have very strong long-term contract coverage. And I think people recognized that those are take or pay contracts and so we haven’t really to this point had many discussions about moving the rigs somewhere else.

Jim Rollyson – Raymond James

Good. Thank you.

Operator

Your next question comes from the line of Joe Hill with Tudor, Pickering and Holt. Please go ahead.

Joe Hill – Tudor, Pickering, Holt & Co

Good morning guys.

Mark Siegel

Hey Joe.

Joe Hill – Tudor, Pickering, Holt & Co

Doug I was wondering if you could comment about operators appetite for term contracts today both on new equipment and renewals of older equipment. I noticed you added a fair number of term contracts during the quarter and I was just wondering what kind of look you can give us real time as to demand for that.

Doug Wall

We know Joe, we told Joe on our last call that typically sort of the fourth quarter where you see a little bit of a low. I’m pleased with the number of new builds that we signed up since our last call and also with the ongoing demand we receive for new builds in the marketplace. I’m pretty pleased there, I think on the drilling side it’s about falling into place like we thought it would no question that it’s been a much harder sell on the pressure pumping side. We have certainly we have pieced together something but we will keep some commitments on some pressure pumping equipment and we are still having discussions with people of further term commitments.

Joe Hill – Tudor, Pickering, Holt & Co

Okay, and then on the third quarter call Doug you gave us some indication that frac price discounts improved about 4% in the southwest. Can you give us an update on what pricing is doing in pressure pumping for the southwest and the App region this quarter?

Doug Wall

Yeah Joe the frac price is certainly across the quarter in the southwest remained pretty stable. They improved slightly but not enough to make a big deal out of it. We certainly have seen a little bit more pricing in the Northeast than we have in the southwest. But I would still say in the southwest markets there is still improvement for pricing in that particular market.

Joe Hill – Tudor, Pickering, Holt & Co

Okay, and then Mark you intimated that you have some balance sheet options if the evaluation remains depressed for the equity. What exactly would trigger some sort of movement on your part to do something and what would that look like?

Mark Siegel

Sure Joe, every quarter our board considers our balance sheet and considers in effect to our strategic options and we consider where we are in the market. And I guess I feel as does most of the board I think that it’s an appropriate thing for us to think about each quarter and really what I wanted to make sure the investors understood is, historically we’ve had a we’ve bought back stock, we’ve had a dividend, we’ve been pretty consistent about all of these things. And I just want to make sure that the shareholders remember that the directors are aware of it and think about in every quarter.

Joe Hill – Tudor, Pickering, Holt & Co

Okay, fair enough I will turn it over. Thanks.

Operator

Your next question comes from the line of Dave Wilson with Howard Weil. Please go ahead.

Dave Wilson – Howard Weil

Good morning gentlemen just kind of a follow on, regarding the rigs the new builds and the 17 that you have left un-contracted. You are fairly confident that it sounds like you Doug that you are going to be fairly confident those will be delivered into the market contracted is that a fair, from what you are saying is that a fair assumption.

Doug Wall

Yeah, I think that’s very fair.

Dave Wilson – Howard Weil

Okay and any gaps between those who got to get into the market whether it’s an incremental rig or maybe a replacement of a rig that’s rolling off a contract or anything like that or do you think these 17 will be a true incremental ad to what’s working right now.

Doug Wall

Well what we’ve seen so far has been sort of true incremental rigs for us. I will say that we have replaced some other competitors in the marketplace I think our customers continuously go through a process of evaluating performance. And I do know of the 13 we’ve already signed I think four or five are more specifically replacing somebody else’s rig. But in our own case we think it’s all pretty much to this point going to be incremental.

Dave Wilson – Howard Weil

Okay, then switching over to pressure pumping comments as far as think reporting fresh pumping have been you might be for a matter of fact this might be optimistic. I was wondering based upon your prepared remarks they are saying that you guys fall into the kind of the matter of fact camp in accurate statement or do you think can view the market is slightly more optimistic.

Mark Siegel

Yeah, I would say it’s interesting to hear you characterize it as A or B I think that we are optimistic about the marketplace based on the view that says that we expect more frac stages in 2012 than in 2011. So that is a reason for our optimism about the marketplace. On the other hand we are aware of what’s happening with natural gas prices and we are one of those traditions about the marketplace given that.

Dave Wilson – Howard Weil

Sure, so Mark along those lines what gives you the most aims on pressure pumping is it queuing up or maybe derailing dislocations from having equipment from one area to the other with then so much that’s really happening. What when you look at that space kind of gives you the most things.

Mark Siegel

No, I guess maybe the right answer is we’ve been doing this for a long time and this management team we are very experienced at going being able to respond to the marketplace. One of the I think hallmarks I hope of our team has been that we’ve been nimble and my own reaction to it is that to the extent to which there is change in a market, whether it’s geographic, whether it’s a commodity, whether it’s regardless of what the cause of the change is I think we are pretty comfortable that we will be able to evaluate the nature of the change and make kind of a smart response to it. And frankly that kind of goes to the beginning of the answer maybe there is some matter of fact about that because I think it’s the sort of thing which this management team has had fair amount of experience with. And so to whatever extent there is change I think we can deal with it pretty well.

Dave Wilson – Howard Weil

Alright, thanks for those comments Mark. And if I wanted Doug switching back on the rigs under contract in 2012 the average of 120. How many of those are non-Apex recently I think kind of back into a number but I just wanted to make sure I was thinking about it the right way.

Doug Wall

Dave I don’t have that in front of me of the 120 non-Apex I would suggest that virtually all of our Apex rigs are under contract.

Dave Wilson – Howard Weil

Sure, okay.

Doug Wall

So I think you can pretty much say that 90 or close to 90 of the 120 are Apex rigs the others would be none. Then it made me slightly higher than that but virtually all of our Apex rigs are under contract.

Dave Wilson – Howard Weil

Perfect that’s what I was thinking. Thanks for the time guys. I will turn the call back over.

Operator

Your next question comes from the line of Scott Gruber with Bernstein. Please go ahead.

Scott Gruber – Sanford Bernstein

Good morning gentlemen.

Doug Wall

Hi Scott.

Scott Gruber – Sanford Bernstein

Question on pumping in Marcellus you highlighted that the backlog of work was down have we completed the eliminated the backlog of the excess backlog I should say of uncompleted wells as the backlog return to more normalized level relative to drilling activity.

Mark Siegel

Scott, I think that’s a difficult question for us to give you a true answer. We believe that backlog of wells that are ready to go on a minutes’ notice is certainly declined. I would still believe there is probably a backlog of wells up there but with various logistics issues like permits and regulatory issues and all those things a lot of people will take a lot longer to get one of these locations or pants ready to go get frac. So I would say that they certainly the backlog of wells that are just sitting there waiting for a frac crew has reduced I couldn’t really comment on as with the true backlog of wells.

Doug Wall

One of the things Scott that we’ve been told is that we believe that some of the customers are trying to develop a pretty good backlog now during this winder drilling period and in fact we will be fracking it as we said towards the end of the first quarter and into the better weather. That’s one of the things that we see and one of the reasons why were in effect saying what we’ve been saying about the cruse beam was accurate the end.

Scott Gruber – Sanford Bernstein

Got it. And so it sounds like it’s just a bit of a timing issue here your ability took place your Appalachian crews back to work does that also reflect moving cruse out of the Marcellus and end of the (Inaudible) is that an element of that as well?

Doug Wall

Well thanks we’ve done a few Frac jobs over in the Unicom but today there is only four or five rigs working in the Unicom or I don’t think there is a substantial backlog of well completed and ready to be franc into (Inaudible) to see full time commitments for cruse over there. We do believe that will come in the next year or so but I think at this point we have not seen a lot of movement. Those crews will go over there and do their franc job and then heads back to their base, which is probably in the Marcellus.

Scott Gruber – Sanford Bernstein

Got it. So you are positive on Marcellus pumping resulted resumption of within the Marcellus. I think it’s both certainly driver there. Got it that’s all for me thanks.

Operator

Your next question comes from the line of John Daniel with Simmons and Company. Please go ahead.

John Daniel – Simmons and Company

Hey guys. Mark, you noted an expectation for more frac stages in ’12 than 2011 is that on the overall fleet or is that on per fleet?

Mark Siegel

That’s a comment about the overall frac stages in the country.

John Daniel – Simmons and Company

Okay, alright. Fine. One other you guys have been pretty candy here on the pricing. In terms of getting down in the gas region as we try to reach out some of the various private guys at frosty oily areas they are increasingly noting the number of increased bidders on work, which we think to suggest that pricing pressures are likely forthcoming in the next quarter or two in those areas. Assuming that plays out alright, you guys have a lot of equipment coming on order does that more than offset the incremental cost, does that more than offset the pricing pressure just that margins can stay flat. How do you see this playing out?

John Vollmer

You know John I think a lot of that equivalent from the time we ordered it and where we planned it might have ended up I think we’ve changed our thoughts or some of them with the new equipments is going to go into those markets. I do think you will see more and more equipments heading into the oilier markets overtime just as you suggested I will just practically will see some additional price pressure in those markets.

But I think each case it’s almost a case, I still think there is a undersupply of equipment in markets like the Bakken. We think there is going to be more equipment taken up in the Eagle Ford certainly the Permian in West Texas I think we haven’t even seen the full impact yet of some of the drilling programs that got underway in 2011. So I think pricing is going to be very interesting in 2012 obviously as you know pricing is dictated a lot by supply and demand in particular markets and we expect a lot of these markets are going to be very dynamic in 2012.

John Daniel – Simmons and Company

Yeah sure enough. One more for me, you guys are moving rig and past when your rig activity is robust the customer sometimes pick up for the rig relocation now when the cycle starts to change, they start trying to push the burden to the driller. So at this point as you guys are moving rigs who is paying for it.

Doug Wall

Typically at this point we have the customer completely pay for both the rig move and all associated cost drill that. I can’t disagree with you I would guess overtime I think we will be a little bit more and more pressured on that and depends how far you are moving things, if you are trying to move a rig certainly out of the Marcellus somewhere else, you may have to help a little bit with those cost. But we don’t anticipate doing that.

John Daniel – Simmons and Company

Okay, fair enough. Okay, guys thank you very much.

Operator

Your next question comes from the line of Kurt Hallead with RBC Capital Markets. Please go ahead.

Justin Sander – RBC Capital Markets

Hey good morning this is actually Justin filling in for Kurt this morning.

Doug Wall

Hey Justin.

Justin Sander – RBC Capital Markets

Hey good morning. I had a couple of questions one is on the pressure pumping side, one on the drilling side. I will start with pressure pumping just kind of looking at the revenue per frac job in the quarter looks like it stepped up pretty nicely from the fourth quarter. Can you talk about some of the dynamics that are impacting us?

Doug Wall

Part of the issue there is was a customer mix issue where we move from not providing sand on jobs to providing sand on jobs. So you have to be a little bit careful with those revenue per job numbers a lot of it is so highly no indicative of the types of customers you are working for. And so I think that probably explains most of the difference there.

Justin Sander – RBC Capital Markets

Got it okay and is that just to clarify is that a shift among customers or is that a change in the contract with an existing customer that’s driving that.

Doug Wall

It’s probably a shift from customer to customer.

Justin Sander – RBC Capital Markets

Got it okay. And then just the next one on the drilling side looking at the cash margin progression I believe you guys last quarter had guided to $500 per day sequential increase with combination of day rates and cost. And you obviously got both day rate same cost improvement but the cash margin came in quite a bit better than what the guidance was. Can you kind of flush that out a little bit more and just talking about maybe where the biggest price was related to the initial expectation?

Mark Siegel

You know really it’s on revenue per day side we accomplished we are introducing revenue per day than we originally thought the time we commented in late October.

Justin Sander – RBC Capital Markets

Got it okay. Thanks guys. That’s it for me.

Operator

Your next question comes from the line of Luke Lemoine, Capital One. Please go ahead.

Luke Lemoine – Capital One

Hi, good morning.

Doug Wall

Hi Luke.

Luke Lemoine – Capital One

Hi, I guess could you remind us kind of roughly where your horsepower is located this time are you currently moving any or do you have any mobilizations planned in your future.

Mark Siegel

You don’t look at the moment roughly 40 and I will talk frac horsepower because I think sometimes we confuse you we are talking total horsepower. But of our high pressure frac horsepower 47% of it’s in the Marcellus about 53% of it is in the Southwest, 140,000 horsepower that’s on order. We have yet to decide exactly where it’s going and I would think that you will see the big or the majority of that likely go into oily markets I suppose to the dry gas market.

Luke Lemoine – Capital One

Okay and then at 47% this in the Marcellus how much of that’s in Southwest Pennsylvania roughly?

Mark Siegel

You know that’s a hard question to answer because that stuff moves around from job to job as you know all that stuff is on wheels. But we do a significant amount of work in the what I’m going to call the higher liquids part of Pennsylvania.

Luke Lemoine – Capital One

Okay.

Mark Siegel

But as you know I mean sometimes our crews from (Inaudible) and from Williamsport if we have more work down on the southern park where we certainly the oily and the liquids content is higher those crews will move down there on a moment’s notice. So we typically it’s hard to kind of say that when we put a frac crew out it’s kind of a moving number, sometimes we have two crews working out of places like Bradford sometimes the next day it will be one.

Luke Lemoine – Capital One

Okay, then John Mark has given us the D&A number for the year could you help us out with G&A a little bit.

John Vollmer

Yeah, SG&A it will be under $70 million or $69 million some there about. For the first quarter I guess it would be above $16 million.

Luke Lemoine – Capital One

Alright, thanks.

Operator

Your next question comes from the line of Andrea Sharkey of Gabelli & Company. Please go ahead.

Andrea Sharkey – Gabelli & Company

Hey good morning.

Doug Wall

Good morning.

Andrea Sharkey – Gabelli & Company

I was wondering if you could talk about the 17 rigs that aren’t contracted right now. I know obviously your expectation is that they would get contracted. But in the event that the market somehow rolled over and for some reason they don’t get contracted how easy would it be for you guys to pull back and not complete them or not build them.

Doug Wall

Well let me first say that we do expect that we will see term contract signed sensibly started our new bill program three or four years ago. We’ve had a pretty steady quarter by quarter base of signing up new contracts and we are pretty comfortable at this point that we will sign contracts. But I hear your point almost monthly we have discussions about what ifs although we are not planning those what ifs.

There is certainly I guess if we chose to we can certainly slow down or defer some of this. The thought the way we build bridge about half a cost of final cost of Arabia is really equipment the other half is sort of rig up cost. So to give you a definitive answer it really depends on how far along we are in that whole rig up process. But certainly to answer your question if we decided to shut things off today yes there could be a significant in our capital plans but having said that that’s not the way we are proceeding today.

Andrea Sharkey – Gabelli & Company

Sure, I will get in that and then I guess the only other question they have for you is some competitors is that they think the rates that are you know most at risk are mechanical rates and FDR rates and things like that. So I was just wondering if you could refresh my memory on how many of your rigs that are operating now? Are those rates come in I don’t know if you give the detail on how many of those accountable type of rates are under contract, not under contract, working in oily basins or dry gas basins.

John Vollmer

Hey Andrea, this is John. I don’t have the contrast by rig size but 100% of our electric rigs are working today. The excess pass that we have today is in the mechanical and primarily some thousand horsepower although there are some 1000 horse powers that need to be brought back to procure 1000 bucks.

Mark Siegel

Yeah, I couldn’t really add too much. I don’t have in front of me the breakdown of the contracts. I think the one thing I would add is that a lot of the mechanical rigs that are working today are in the west Texas region. And we anticipate that demand for those kids of rigs in that region will remain strong.

Andrea Sharkey – Gabelli & Company

Okay, great thank you.

Doug Wall

Things are particularly well suited to that kind of work and so we are not expecting to see a substantial drop in our conventional rig count unless there is a huge change in the overall rig count.

Andrea Sharkey – Gabelli & Company

Okay, great. Thanks a lot.

Operator

Your next question comes from the line of John Tademir with Canaccord. Please go ahead.

John Tademir – Canaccord Genuity

Hey, thanks for taking my question. I guess one of the things I want to follow up was the mention of you know perception evaluation and options that you may have on enhancing that. I mean right now I mean talks about share buybacks are dividends potential. But you know right now you’ve got a CapEx program and you are not sitting on a bunch of cash to do anything would you have to, to buy back stock would you borrow or would you have to make a decision to your spin less capital. I’m not telling that we would do that right away but.

Doug Wall

I mean what; I am not doing this we do that right way. As I see it John actually asked me to speculate on what’s the possibilities are. And frankly what I think is you are right a lot of possibilities here we could if we made a decision to reduce CapEx. We could borrow for a buyback we could do any number of things but thin for our real choice is to see. And we think that’s a very good thing provides a lot of options to our shareholders.

John Tademir – Canaccord Genuity

Okay, so you would contemplate borrow I mean well anyone do answer the question. Let me move on back to and I think that start to drinking (Inaudible) fine on those on horsepower edition on average you will have working in 2012 versus 2011. Is it a 10% increase or 20% increase we’ve given up the number but what on average how much will you have.

Doug Wall

John I’m not sure we have a answer or ever prepared thing we are going to have a look at that and see if Mike can get you an answer that satisfy that.

Mark Siegel

Well I’m just trying to think of what you have a 20% increase in revenue generating horsepower increase in 2012 over 2011. What’s the average because I think when we look at it we are trying to dye all of us in the average working horsepower is going to help us understand okay what if there is no you have 20% more horsepower working in 2012. Now revenue therefore has increased by 20% all else being equal or not equal. So as Doug indicated we don’t have those numbers here.

John Tademir – Canaccord Genuity

Yeah I understood.

Mark Siegel

A lot about it that way believe that the average horsepower working in 2012 as things have as we discuss would be more than 20% higher. Well I think about that more.

John Vollmer

Yep, and then just I guess maybe this is a similar question too. But I think you got just the math if 140 rigs right now working they are not on contracts and about 100 bricks in dry gas basin that are working.

As we transition from oil, gas place to oil place. It’s not going to be seamless some rigs are going to be like guess pretty dynamic last in a month or so. Are there rigs that are actually I would imagine if you are making a decision let’s say to evaluate Haynesville some you know just the much okay we are going to move this rig but we were not going to take this rig with us. Have you seen decline in day rates or, are people negotiating with better rates in some rigs versus moving core into realize us we are going to drop here and move somewhere else.

John Tademir – Canaccord Genuity

I think the question is in a marketplace that’s dynamic the customers’ approach you with all kinds of possibilities yes as we seen a change a negative change in pricing in the rib market.

Mark Siegel

No, so the answer is pricing is steady with an upper BIOS I think judge said that and so we are not seeing anything like that at the same time obviously customers are more anxious to pursue their oil and liquids rich plays than they are to pursue their dry gas plays right this minute, which you know and is obvious to everyone on the call. So all the dynamics are at work but I think our customers realize that there is such a strong demand and backlog that demand for oil capable for rigs capable for generally for oil and rigs that in the fact that as rigs are released they migrate over and that’s what the real point that we try to make in our presentation.

Doug Wall

Okay, thanks guys. That’s all.

Operator

(Operator Instructions) and your next question comes from the line of Waqar Syed. Please go ahead.

Waqar Syed – Goldman Sachs

Thank you. My first question is that just going back to John Daniel’s question that some of the E&P companies are saying that even now they are seeing more pressure pumping companies and maybe drilling contractor is bidding for contract. As a service company are you seeing more opportunities to bid to E&P companies that’s well in the place?

Mark Siegel

I guess that the question Waqar is that as our customer base expanding the answer to that question is yes.

Waqar Syed – Goldman Sachs

Okay.

Mark Siegel

I’m not sure whether it’s we think that our company has been transformed and customer that are now become customers who were customer’s couple of years ago.

Waqar Syed – Goldman Sachs

Alright.

Mark Siegel

You know Waqar one of the other issues that we’ve seen in the pressure pumping business over the last couple of years and because of the size of these crews it’s got so big. You had a very high accounts concentration if your horsepower with a limited number of customers so as new equipment comes into the market it does allow you to kind of expand your customer base. So I would say the answer to that is yes definitely we are trying to expand the number of people that we’ve been to. I think that’s just a natural progression of trying to expand your customer base.

Waqar Syed – Goldman Sachs

And also it sees like as we look through the data that that the number of just the E&P companies is expanding as well. The new entrants on the E&P side coming in as well either from private supply activity is that what you are observing as well.

Mark Siegel

Yes, I think that’s correct.

Waqar Syed – Goldman Sachs

Okay, that’s one and secondly in terms of your, did the high spec rates that you have is there any new changes in design that you are implementing for the new rates that you are going to be adding in 2012.

Mark Siegel

Yes there is but I would be hazard into go much beyond that in terms of your answer we are always looking at new and more innovative ways of improving the efficiency of rates both in moving them quickly. Virtually, every year we introduce new little bits of technology to continuously try to improve the efficiencies on these rigs and yes, Waqar we are in the middle of some pretty dramatic changes in our Apex rigs.

Waqar Syed – Goldman Sachs

Okay, and these new rigs are there more towards the skid mounted type or they are going to be more just the normal moving from one location to another.

Mark Siegel

I think you are seeing more and more people certainly interested in not only the walking tight bridge but a combination of the benefits that you get from a very fast moving rigs. How do you skit them and how do you get them it’s a drill two and three will pass very efficiently.

Waqar Syed – Goldman Sachs

Okay, alright. That’s all I have. Thank you very much.

Operator

Ladies and gentlemen that concludes all questions that have been answered. I will now turn over to Mark Siegel for closing.

Mark Siegel

I would like to thank all of the participants for their joining us today on this conference call. And look forward to our next call as we report first quarter. Thanks everybody.

Operator

Ladies and gentlemen thank you for your participation in today’s call. This concludes the presentation. You may now disconnect and have a great day.

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