Good morning and thank you for joining us for the RPC Incorporated’s fourth quarter and annual 2011 earnings conference call. Today’s call will be hosted by Mr. Rick Hubbell, President and CEO; and Mr. Ben Palmer, Chief Financial Officer. Also present is Mr. Jim Landers, Vice President of Corporate Finance. At this time, all participants are in listen-only mode. Following the presentation, we will conduct a question-and-answer session. Instructions will be provided at that time for you to queue up for questions. I would like to advise everyone that this conference call is being recorded. Jim will get us started by reading the forward-looking disclaimer.

Thank you and good morning. Before we begin our call today, I want to remind you that in order to talk about our company, we’re going to mention a few things that are not historical facts. Some of the statements that will be made on this call could be forward-looking in nature and reflect a number of known and unknown risks. I’d like to refer you to our press release issued today along with our 2010 10-K and other public filings that outline those risks all of which can be found on RPC’s website at www.rpc.net. In today’s earnings release and conference call, we’ll be referring to EBITDA which is a non-GAAP measure of operating performance. RPC uses EBITDA as a measure of operating performance because it allows us to compare performance consistently over various periods without regard to changes in our capital structure. We’re also required to use EBITDA to report compliance with financial covenants under our revolving credit facility. Our press release today and our website provide a reconciliation of EBITDA to net income, which is the nearest GAAP financial measure. Please review that disclosure if you are interested in seeing how it’s calculated. If you’ve not received our press release, please call us at 404-321-2140 and we’ll provide one to you immediately. I will now turn the call over to our President and CEO, Rick Hubbell.

Thank you, Jim. This morning we issued our earnings press release for RPC’s fourth quarter ended December 31, 2011. Following my comments, Ben Palmer will discuss our financial results in more detail. I’m pleased to report that RPC generated record revenues, profits, and return on capital for the full year of 2011. I’m also pleased to announce that RPC’s Board of Directors in response to our strong results and balance sheet and as a show of confidence in our company’s future prospects, increased the quarterly dividend 20% from $0.10 to $0.12 per share. In addition, our Board approved a 3-for-2 stock split. Notwithstanding our record results for the first time in recent years, we experienced a sequential decline in our operating performance. Ben Palmer, our CFO, will provide more details.

Thank you, Rick. The quarter ended December 31, 2011 revenues increased to $482.8 million, a 47.1% increase compared to the prior year. These higher revenues resulted from a larger fleet of equipment, higher utilization across most of our service lines and improved pricing. EBITDA for the fourth quarter was $171.8 million compared to $125.2 million for the same period last year and our operating profit for the quarter was $122 million compared to $89.8 million in 2010. Our net income during the current quarter was $74.6 million or $0.51 diluted earnings per share. Cost of revenues increased from $174.5 million in the prior year to $268.5 million in the current year. This increase in costs results from a higher business activity levels and associated costs including total employment costs and materials and supplies. Cost of revenues for the fourth quarter as a percentage of revenues increased 53.2% in the prior year to 55.6% due primarily to increased costs of high-demand raw materials used in our pressure pumping service line. Selling, general and administrative expenses during the quarter were $42.1 million, an increase of 33.9% compared to $31.4 million in the prior year. However, because of our ability to leverage these fixed costs over higher revenues, SG&A costs as a percentage of revenues decreased from 9.6% last year to 8.7% this year. Depreciation and amortization were $49 million for the fourth quarter, an increase of 41.5% compared to $34.6 million in the prior year. This increase is a result of additional equipment that we replaced and serviced over the past 12 months. Revenues in our Support Services segment which comprise mainly of our rental tool service line increased by 16.5%. This segment generated an operating profit of $14.5 million compared to $10.5 million last year primarily due to higher pricing. Now…

Thank you, Jim. RPC recognized early the increasingly, service intensive nature of shale plays and has been able to capitalize on the opportunity. Despite these successes we are subject to the cyclical nature of the oil and gas industry caused by the dynamic interaction of commodity prices and customer and competitor decisions regarding their activities. The fourth quarter of 2011 was the first in the last 10 quarters that RPC did not generate increased revenues, net income and EBITDA. Management is aware of the current trends and we are monitoring them closely. I would like to thank you for joining us for the conference call this morning and at this time we will open up the lines to answer any questions that you may have.

Thank you, sir. (Operator Instructions) Our first question comes from Neal Dingmann with SunTrust.

Say, Rick or Jim, just a question on obviously first and foremost on the cost. Some of your competitors are obviously saying the same thing and I wanted is as you see that kind of play out through the remainder of the year maybe if you could give us a little color on it and break those up a little bit on the personnel, raw materials and then perhaps the movement cost of reallocating some of the fleet, just your thoughts around those three particular costs.

Neal, this is Jim, just kind of a first overarching comment. I think that all of our peers have noticed the increase in raw materials prices or labor prices and have addressed different parts of them differently. So I think one might surmise they are having a problem with raw material prices and I think that’s probably sincere. And I think at this point that the price of, we all know about [the cost]. That continues to increase where we’ve worked on locking up with some suppliers there. Among proppant it appears that there is some level substitutability from the higher grade stuff to other grades and there appears to be more availability coming to market. So just sort of faulty agreement either the prices of proppant perhaps wouldn’t be increasing as much it has in the past. Labor still an issue. The transition cost is more one of opportunity cost on revenue than real cost that will hit the P&Ls. So this is kind of we are looking at.

Yeah, I think I will concur with that final point that Jim made. I am sure there will be some incremental cost but don’t believe that would be that significant. We’ve moved from basin to basin with customers before. So we’re obviously, we think those opportunities and we’re pretty well strategically located that we can moved the equipment around without too much incremental cost.

And then do you see more of this. I mean given I am looking like the prior slides and comments. I mean you had of that 25% of capacity back in the second quarter in the Haynesville and another 23% in the Marcellus. Do you see given your state of comments about the gas price in those comments, moving a fair amount of that or are you still keeping most of that working in those regions?

I mean that’s not related to our comment, people are making those decisions and they are making movements and that clearly impacted our results. So I do see as moving more towards oily and liquid-rich basins with our customers. We do believe those opportunities are there, hopefully those areas won’t. We are early, may be a little bit earlier than some others in making these moves and may be it won’t be so crowded when those moves occur. And with respect to the impact on our results, we have only a certain number of frac rigs and crews. So it doesn’t take many of those to become, whatever you want to call it, dislocated or temporarily setback or with lower activity levels to impact our results. So, we are not yet panicked. I think we are just in a transitory period here. I mean, natural gas prices have moved down very, very quickly in a very short period of time. And I think also with the holidays, may be have some natural time for our customers to be making these kind of decisions. I mean, we already knew or our expectation there was going to be a little bit of slowdown for the holidays and may be that just sort of dovetailed in to the other decisions as well.

And Ben, last question I could, just on that, the overall capacity, any touch. Now I know you mentioned going to 660 at the end of the first quarter, were there any thoughts now by adding more capacity. And if so, is there still quite a long lead time to do that. I mean, I am wondering if there is, would you think about ordering more as we speak?

We have talked in last couple of quarters that we were done for ’12 and at this point I think that’s still our decision, we are not changing our mind on that. In terms of lead times, we haven’t been out there ordering so. We don’t know how those may have changed recently.

And our next question comes from John Daniel with Simmons & Company. John Daniel - Simmons & Company: At this point, have any customers which you have contractual relationships, have they elected to use only the minimum amounts of services under those contracts?

John, this is Ben. I don’t know if I can definitively say they’ve managed it to the absolute minimum but as I’ve indicated in the last couple of quarters, there were opportunities to do more work than we were doing. I would say, on some basins, customers were doing absolutely as much as they can and hitting some of our, we call them maximums. But some of the levels where maybe they get some efficiencies from ever higher [shale gas] and there are other areas where, yes, and they don’t necessarily tell us, hey we are doing the minimum, because but certainly you can infer that especially looking back now. John Daniel - Simmons & Company: Okay. But as this stuff then becomes that open in the spot market, can you characterize for us hopefully quantify for us, the rate of change in pricing?

John, this is Jim. As things go in the spot market, I think the dry gas basins like the Haynesville, I think, you are going to see pricing. You are seeing pricing declining that’s for sure in the spot market. In places like the Permian, the pricing is stable and perhaps moving up a bit. A good question will be the Eagle Ford. About the Eagle Ford we don’t really know because none of go to the spot market there and as you and others know, we aren’t yet doing the pressure pumping in the Bakken, so we couldn’t really speak to the spot market pricing there. I think in the Marcellus, spot pricing is soft as well. So, I think the Haynesville and the Marcellus will be weak carriers.

I would add another way again. We have to admit to you that when we sat here three months ago, we didn’t expect to be where we are today, but national gas price again has moved down very quickly and customers were certainly making different decisions and/or making decisions that were impacting activity levels. In terms of pricing, again this happened so quickly. Unfortunately, we can’t provide a tremendous amount of information on pricing trends because we have been here too far pretty well locked up. So we’ll know lot more this time next quarter. John Daniel - Simmons & Company: Fair enough. My experience is lot of times when you see in the holiday down time to be extended if you will that sometimes bleeds over into January. Has January started of slowly for people to come out of the gates working and can you characterize what you are seeing where we stand right now?

We think people are coming out of gates working more and we know that. Factually in some cases Ben reported referred to raw material shortages slowing us down. We are still dealing with some of those, but holidays are over again.

We have specific examples of things that were disrupted in the fourth quarter that have improved but I said before too, things are always very volatile and so there could be other things happening as well. But there have been some very positive developments but also there could be other negative developments as well. So I am not making any predictions on where our top line results are going. John Daniel - Simmons & Company: Okay. I know you don’t want to make a prediction just yet but I have to ask, you’ve got the 70,000 horse power in Q4, how much benefit of revenue did you get with that equipment? Just trying to frame where Q1 might look from revenue given that plus the other 60,000 and I know, I understand 50,000 is rotational and that’s my last question, I’ll turn over?

The horsepower we got in fourth quarter came late in the fourth quarter, so we do not contribute that much.

Our next question comes from Robert MacKenzie with FBR Capital Markets.

I was wondering if you could help me understand better some of the project delays you talked about, customer delays that you experienced, seemed to be a little more severe than what we've seen at some of the competitors that reported today. Can you give some more color as to how that impacted you guys and what the details of those issues were?

Rob this is Ben, we don’t ever talk about specific customers and things like that. I guess, anecdotally I haven’t studied other peoples’ releases that closely, I expect we’re one of the first smaller North American focused groups to have them some of the larger players that also experienced the North America weakness, so it hits us more, I guess more significantly, because it’s across our entire business rather than just a portion of our business. And I would say other than that, I will point out that I think another dynamic that’s going on here that will make it difficult for anybody to sit here and try to predict exactly where our revenues and maybe others are as well and these dry gas plays that our customers are moving are examples of where they are moving away from. We’ve had very service intensive jobs that generate tremendous amounts of revenue, but in actuality, lower percentage margins and we’re going to be moving in the basins which typically aren’t quite as service intensive. So we may have lower revenues, but we would hope and expect we may have better percentage margins. So the numbers are going to moving around and it just depends on you know where that mix falls out.

And what drives that difference and why would the less service intensive business you’re talking about will have higher margin?

Well, some of that gets down to pricing, I don’t want to say that you know some prices are better than others and how things turn out in the end, I mean you can’t always predict the bandwidth but you’re going to turn out on a specific situation when you go and negotiate with customer you do the best you can. But that also as we’ve talked about before you know in many situations we’re giving up higher percentage margins to get more revenue. So my point is, the returns maybe the same, could be even higher, maybe a little bit lower when we move into these other basins, but the dynamic, the mix between revenues and percentage margins could change.

Okay. And if I make and expanding on John’s question, at the end there, you know apart from the new capacity added towards the end of the quarter, do you have any spreads that were materially underutilized during the quarter? And where and why do you attribute that?

Yeah, Rob this is Jim and I think you’re kind of rephrasing your first question again, I mean the answer is the yes, we were underutilized in one area and it kind of doesn’t matter where because we don’t say any answer, we didn’t have sand. So we had a fleet that was underutilized because it didn’t have sand. And in another case, you know we had some customer transitions and then another case we just had a customer moving ridge from one basin to another and so those are three examples and the only three actually of how equipment was underutilized in our pressure pumping fleets.

Okay, that’s helpful Jim. Thank you. And then, to the sand issue and you’re alone in that, I mean others have had the same issue, what has changed or what have you done to fix the supply chain issues and how long does that take you think before you kind of don’t expect to see supply issues anymore?

I think we will, as soon as we beat one down another one is going to come up. I think it’s always going to be an issue. It’s always a lot of work. I think some of the other issues we had we have addressed crews back to work. You know, this is not only having the supply available but it’s having to move the right amount, in the right time, moving in the right direction to arrive at the right time. We’re having to, you know we are did on our balance sheet, we’re having to built up our inventories of supplies, I think that’s the right thing to do. So that requires some more working capital. So we hope overtime to get better and better at it. But I think it will be more noticeable sometimes than others, but I think it will be an ongoing challenge; there is a tremendous amount of work, I am sure you have seen it probably laid out on us, so there is a lot to do it, there is a lot of complications. But it’s all about relationships, locking up supplies as best you can and creating new supply routes and improving your logistics and towards the trans-loading capabilities and we’re getting better and better that every day.

Okay, great. And then I guess a final question on this topic from me is how vertically integrated are you in terms of say the sourcing of sand, I mean, are you buying directly from the mines and arranging your own railcars, are you buying from somebody locally in the different basins. How do you think about your sourcing there?

A reasonable question, it really various by basin, it’s a lot of differences and we in-source in some cases, we outsource in another cases and it’s really all over the board. Eventually it depends on the region and prior relationships and stability and capability of those and so a very...

Okay. Thanks and my final question is related to the stock split. I just wondered if you could share with us the rationale of splitting the stock, call it you know closed yesterday at $17.50, you know, pre-market it looks like it’s sub $17. What’s the rationale for splitting it here?

Rob, this is Jim. A couple of things, you know our profile well. We have limited float, and this is one way to increase the floating shares. It doesn’t change anybody’s percentage ownership obviously, but it does increase our float and we’re proud of that. This is a pattern that we have followed for a long time now, and has paid off for since generally favorably received. Notwithstanding the current quarter and the sequential issues we’re all discussing this morning, RPC had good year in 2011 and we feel, we continue to feel good about the long-term in the industry. And so we feel that having more shares out there, continuing with a conservative plan, keeping one of the strongest balance sheets in the industry, we think shareholders who are with us and see a little more liquidity in the end, will be rewarded. So that’s a longer term answer, but that is our intent.

And the risk of kind of reduced potential ownership from certain fund if it dips below in a certain price threshold you felt was acceptable?

Yes. We think that risk is acceptable. A lot of our well -- some of our large institutional shareholders have been with us for a long time and we understand they have investment criteria and mandates, but we’re not fully concerned about that at this point.

Our next question comes from Scott Burk with Canaccord.

So just to be clear, so when you get to talk about product transitions for the clients that basically means there is a moving fracs place from one like a gas basin to an oil basin or is there something else involved there?

Scott its Ben, that’s typical the case. And I would like to say here absolutely we got to going one of the other and we know in everyday it’s exactly where its going; no we’re not suggesting that but to the extent that they have shutdown very recently with the way natural gas prices have gone and going their recent positions; we are in transition as well, so its where we are.

Now if that situation comes up, say you’ve got a fleet in Marcellus where they are not going to doing more activity and they are going to move it to – you went there something like that; under your contracts what kind of recourse, what kind of revenue do you still receive for that fleet or if any?

Every situation is different, but if they are under contract, we would get, it depends on the amount and they would tend to move with us and in each one of these cases, these are not necessarily ones that we’re under firm contract and commitments in every contract is a little bit different. So to answer that, I mean maybe that this is a situation where there is contract that not (inaudible).

And in that situation more likely they wouldn’t take that fleet to move or something. Okay, so you know this has been kind of, your report we’ve seen is kind of starting to look like a bit of a trend especially you know weakness in the gas basin, but if you look at the oily basins, I remember you guys have a lot of your stuff in the Permian for example is on spot contracts, what are the pricing trends over the last couple of weeks and is there starting to be a negative impact from additional [equipment], look like it’s going to move into those oily basins?

The last couple of weeks, it’s hard to say I mean we do operational reviews fairly regularly. We commented earlier that we think Permian basin pricing is holding. However, if the US pressure pumping fleet is supposed to grow 28% this year, but if in certain basins it grows more because it’s decreased in other basins, that could have an impact. So in Rick’s comments he said we are watching trends, one trend would be a whole lot of migration from dry gas basins to places like the Permian. We haven't seen that yet, but we are certainly watching for it. So that's cautionary I think.

Okay and then another question kind of regarding the sand issue or sand availability. When you have a downtime on or when you are not able to get the sand to a fleet, obviously you don't driven into that situation, but can it be that you end up cancelling or a client could cancel a contract because you have not been able to get the sand to the location for a certain amount of time.

In a severe case I guess so, but typically in that situation we and the customer work very hard “ensure” or minimize the risk of that deferring and we have in some prior quarters had to take, some could describe it as extraordinary measures to get sand you know incremental amounts of sands to be able to do the amount of work we wanted to do, so that does create inefficiency when that happens and when that happens to us and I am sure it has happened to other people as well. So you try to do everything you can for the customer to meet those demands and that sometimes can result in higher costs that aren’t necessarily recoverable.

And then another question about the pricing, you’ve talked in the past about you being able to get pricing increased on your contracts to handle raw material costs. How much of the reduction margins for the fourth quarter is due to the fact that you had price increases that you have not been able to yet translate into price increases. And are you still going to be able to get those price increases or do you actually expect that operating dollar margins will start to deteriorate here?

So you may have, everything else being equal a small degradation in your operating margins and all you have done is, you recapture that cost increase, you haven’t also added that same margin to it. So you do have some small degradation. So if there is continued escalation in prices, all we’re doing when we hit those repricing points is again we’ve kind of caught up from where we were hurt in the back or we adjusted prices, but we still would be actually be subjected if prices continue to increase. So it’s certainly better, much better situation than if there was no ability to do that obviously. But it’s not a perfect panacea. It doesn’t translate into absolute you know the same margin as you had before. And there again, there is so many dynamics, there is volume of work and everything else that goes along with that, but that’s how the contracts work.

So I am sensing some concerns about Sanford Play growth. For the pressure pumping fleet, obviously you had talked about that a bit last quarter. But can you talk about your capital expenditure plans for this year with that in mind?

Well, we said in prior quarters that, we were looking at something less than this year, I think we were saying we were going to be around the 400 to 425. We ended up at 416. I think we were saying that our early thoughts were less than 11, may be 350. I think today, as we sit here today, we haven’t made any definitive adjustments to that. But we are reviewing it as we always do. The good thing about it is, there is a lot of flexibility even in that $350,000 number.

Our next question comes from Andrea Sharkey with Gabelli & Company. Andrea Sharkey - Gabelli & Company: I was wondering if you could maybe give us a little bit of a more quantified sense, the sequential decline in your technical services revenue is about $20 million. Can you kind of split that out how much was holiday delays, how much was moving from one region to another and then how much was material, maybe just broadly.

That’s a little bit difficult, but let me try to approach and answer it. I would say that somewhere between 40% and 50% of that decline might have related to raw material shortages and delays. Maybe the second largest share of that would relate to holidays and I think that is probably about, all I can say is definitive. Andrea Sharkey - Gabelli & Company: And then I was just curious if you could refresh us on how much of your pressure pumping equipment is currently operating in the spot market and then how that number will change as the year progresses assuming that would ever you know on contract now that rolls off, doesn’t get re-contracted?

Does not get re-contracted, okay?

Still about what, 60:40. Contract 60 going to spot 40 and you know different variations in that contract versus spot, but I would, I think right now, today, I don’t know that we see or would project any significant change in that, I mean got to be some that will come off contract, we have already said we are going to obviously explore opportunities with others on the contract. But right now, I don’t see that changing significantly.

If you want to know, if there is any bias one way or the other, just any risk one way or the other, it might end up being slightly less contract by the end of (inaudible) based on what we know right now which is, what we know right now is in the midst of a pretty dynamic environment. Andrea Sharkey - Gabelli & Company: The last question for me, I know the SG&A was up sequentially, maybe about $5 million, can you just kind of give us a sense of what those extra costs were and is that $42 million or so runrate kind of going to be good as you go through 2012?

I concur with Ben’s comment, I think we had some additional employment costs and a little bit of a yearend bad debt accrual true-up which would have accounted for most of that SG&A increase?

In terms of the number going forward, it is a little bit like our CapEx. It is under review and we are always updating, reviewing contingency plans especially when we have a little bit of a jolt like this. So we have been through this many, many times and it’s not like we are starting over. So we did this not too long ago, not that we are doing it, but we have gone through contingency plans before. So we are prepared and there is a lot of flexibility and we don't have any other large growing SG&A costs like in other words to say that we can't control at this point and minimize those increases going forward.

Our next question comes from William Conroy with Pritchard Capital Partners.

Probably really following up on some of the other ones. First one is housekeeping, maybe more you Benefit. Is the 60,000 horsepower that you anticipate bringing on in the current quarter is all of the cap spending for that contained in the ’12 budget or is some of that paid for in the ’11 budget?

Yeah, some of that's in ’11. Obviously, the final payment that will have to be made in ’12.

And maybe then related to that if I picked up what your plans were for additional horsepower during 2012, then the vast majority of the CapEx budget is directed away from pressure pumping. Or at least in terms of adding capacity?

You are referring to the 350 number you are trying to kind of reconcile that back to 350.

Yes.

Well, the 350 number could have at some level included additional pressure pumping capacity but nothing definitive enough to label it as such if you will. I understand what you are saying, but yes by and large there's a lot more on other service lines in ’12 than has been for some time.

Okay. And then shifting gears back to the current state of pressure pumping. If sort of memory serves and I stitched some things together between the Haynesville and Marcellus and the Fayetteville I think of you guys maybe roughly 50% of your capacity is exposed there; A is that correct and maybe B, whether it is or not, how far for along do you think you are in terms of transitioning your capacity out of some of the gas field areas to whatever they have to go?

Just to the second part of your question, the honest answer is we are, I indicated earlier just some months ago, we wouldn’t think we certainly like this, we’re in the midst of transitioning this equipment. I couldn’t tell you that we know exactly where every idle or underutilize fully is going to be working next week.

Okay. actually that does and is my some quantitative framing at least that might be beyond monument to Yankee stadium on that?

Bill, this is Jim let me repeat an answer and just make sure we’re on the same bench, because that’s a good question. Between I think you were asking Haynesville, Marcellus and Fayetteville, if you add Haynesville, Marcellus and Fayetteville you get about 53% or 54% of our capacity. So I think you said 50%. So you were pretty close.

And where those are going to land we don’t definitively know to ones that we’ve talked about resulted in some of the revenue decline and we’re not making predictions about that either, whether we’re going to go start working in existing basins where we’re going to start to go to earlier basins, I expect it will directed more toward the earlier and liquid rich basins but we are evaluating options right now.

Our next question comes from John Lawrence with Tudor, Pickering, Holt & Co. John Lawrence - Tudor, Pickering, Holt & Co: Just a question, another pressure pumping question I imagine that, just on the capacity in gassy basins, are you seeing anyone actually trying to back out a contract or they just moving the capacity ?

No. No examples of people backing out of contracts. John Lawrence - Tudor, Pickering, Holt & Co: Okay. Then I guess just switching gears on coiled tubing side Does that market still feel undersupplied, any change in there and then how much capacity you are going to have in 2012?

John, this is Jim The market still feels undersupplied At this time, coal tubing and pressure pumping go hand in glove in these unconventional completions as we all know But that still feels undersupplied What we are adding is all large diameter and we are adding five more units this year, John somewhere at the end of the year. John Lawrence - Tudor, Pickering, Holt & Co: Okay. Is kind of labor the key issues as far as getting those things working?

Yes. For coaled tubing ends, yes. We were going to add four this year. John Lawrence - Tudor, Pickering, Holt & Co: Four, thank you.

Our next question comes from Doug Garber with Dahlman Rose.

Jim, just quick housekeeping to follow up on that last question, how many coiled tubing did you do at the end of the year in 2011?

Okay, good question. We ended the year with 49 coaled tubing units Doug and we believe that the current plans are at the end of 2012 we will have 53.

Okay. And what is, one of the larger units, would you be willing to share kind of what do you think a range of annual revenue might be for a larger unit on a run-rate basis?

Dave, the day rate it kind of depends on utilization but it could be somewhere in the $6 million to $8 million annual revenue range.

Okay. That’s helpful. Thank you. I wanted to follow-up on, not having the crew work because you couldn’t get sand and try and understand why the sand was not shored. I know in the past you’ve been able to truck sand in a pinch, maybe at higher cost, but still you were able to get it. And I also want to understand, could you maybe switch to a different grade of sand, maybe some of the finer sand versus the coarse sand which is in a tighter supply, were the customer willing to do that?

Many times, yes, that is you are able to do that working with the customer. In this particular example, it was the type of the sand, it was the coarseness of the sand and it just was not, it was not available when we needed it and in a matter in a time that we can make it work for the customer. So we have resolved that and we are back to work in that particular situation. So, it is very specific situation, it didn’t impact necessarily an entire region and it didn’t impact multiple crews or frac spreads. That was sort of a specific example, but definitely had an impact.

So this specification comes from wasn’t willing to use kind of a finer sand, he really wanted coarse sand.

That’s right.

And also Jim, you made a comment earlier on related to the substitution of higher grade to other grade of sand and I want to understand if you are talking about going from coarse sand to fine sand or are you talking about going from perhaps resin coated sand to raw sand.

Doug, more of the latter but core product, a little bit. We have been hearing from our operational folks that in previous times of low commodity prices customers were more willing to go to cheaper products because it’s a good financial decision. What we are told now is that tendency is still there but it is not as pronounced as it was but so we are talking about shades of gray here but in general we are talking about going from higher grade resin coated sand to raw sand as an option both because of cost reasons and frankly its because of availability.

Okay. Just wanted to another house keeping question, the percentage of your revenue from pressure pumping, you have given that historically and also the coil tubing and those things you can share for the fourth quarter?

Sure Doug, glad to. I would like to pressure pump revenue as percentage of RPC’s consolidated revenue was 53% for the fourth quarter. Coiled tubing was 11% of consolidated RPC revenues.

Our next question comes from Ben Swomley with Morgan Stanley.

Hi, I was just hoping, I was wondering if you could expand a little bit for me, is the shortages that you’re seeing with sand or the tightness that you’re seeing with the sand supplies, did availability of resin coated sand or is it transportation issues?

Ben I might have to comment its logistics, in other words sand may be available, but it won’t be available, but it may not be right here where you need it and so there are logistical issues. You can truck the sand and we do for customer relationship reasons, it’s also expensive. On the flipside, sometimes you end up with sand waiting on railcars siding and the customers aren’t ready to go or there is a delay for some reasons, so you incur the [de-remittance] charges. So there is a kind of a whole range of issues that come up, that keep you from getting the right sand, at the right place, at the right time unfortunately. And the example that we cited earlier for fourth quarter it was an issue of not being able to get the sand in the right place.

Our next question comes from Ryan Fitzgibbon with GHS [Global Hunter Securities].

Curious if you can walk us through how contract negotiations with your customer base, or if that’s a changed at all in the last six months as well as pricing and number of stages you are guaranteed?

That was changed in the last six months. I don’t know the negotiations that changed that significantly and in terms of – I don’t know that we have any specific here, any specific examples or commentary on that in terms of the differences. It varies by basin you know we don’t have enough contracts in specific regions to be able to compare and contrast, and one that you understand your question I think it’s a reasonable question but I don’t think we would be able to collaborate to fully on that; I am not aware of any significant changes in the form or structure of the contract.

Okay, fair enough. And then the 65,000 horsepower you have committed on this quarter, is that contracted and can you tell us where that’s going?

It’s going to basins where we think it’s going to work and some of it is backup rotational fleet and some of the other we think will work, we’re not sure to be under contract thus far at this point; kind of depends on which basin it goes to first of all, but we’re not sure.

And then I guess last one of the pressure pumping side, more technical services. If I look over margins we’re in Q4 and let’s say when your crew cost remain high and supply chain initiatives continue to impacts you and the industry, any reason to think that margins shouldn’t generally trend down through ‘12 at this point; what’s your outlook there?

It could turn down for some industry reasons and we expect that with less revenue disruption will be more efficient, so SG&A as a percentage of revenue would be lower in that case. So you’ve got a couple of forces working against each other; it’s hard to know which of the two is going to be more pronounced at some period.

Yeah, and as I kind of alluded to earlier on in our conversation, there is a lot of dynamics going on with very, very service intensive dry basins moving into other less intensive and so the margin, revenue and margin dynamic is – going to be changing and where that’s going to shake out is unclear. Right now, we are not expecting all things being equal. We are not expecting significant declines in margins with everything happening the way it is right now with customers moving basins and that’s going to effect concentrates. Hopefully, activity levels will go up as high as the amount of competitors in a particular region and hopefully we’ll get back to the levels of activity where we have been working and we can maintain margins. But it’s hard for the dynamic.

And then the $350 million CapEx number that was discussed earlier, how much of that would be maintenance CapEx or is that not included in that number?

No, that is included in that number. I would say the full CapEx number is probably as much as $100 million, probably right now in that number on the pressure pumping side is $50 million plus, that’s refurb run that we have laid out and we’re in the process of executing; overall it’s north of $100 million.

And we have a follow-up question from John Daniel with Simmons & Company. John Daniel - Simmons & Company: Last year there were lots of rumors that you guys were up for sale and of course you guys widely didn’t comment on these rumors. But in Q4, you were active buyers of your stock and I am just wondering if your legal counsel would allow you to buyback stock if you are actively running a sales process?

No, and research that. John Daniel - Simmons & Company: Okay. I would assume no; but I just wanted to drove that one out?

I would assume no too, but I haven’t looked into it. John Daniel - Simmons & Company: The other question I’ve got is a follow-up on the G&A, Ben, I couldn’t tell if you said the whole G&A flat from the Q4 level, because then Jim mentioned that Q4 included a bad debt true-up and so, as a big part of that cost, if that were the case, why would be looking at that?

Fourth quarter win process, again we’re looking at all that stuff. Fourth quarter was a little bit higher than the third quarter. It did have, it had, maybe a little bit of a bad debt true-up, it did have a restricted thought for rate true-up and not only get into – that’s what we do that annually and that was a lot bigger than normal for various other reasons. But, so I would expect that, I don’t expect it to increase significantly from that fourth quarter level unless we make definitive additional actions from this point forward, it’s not growing rapidly, you know kept it pretty well under control and we’re not adding a tremendous number of people or resources and things like that. So I don’t see it rising significantly from this level. John Daniel - Simmons & Company: Alright, fair enough, and you guys have been very generous, but I got to ask one more since I got you. You mentioned last quarter that coiled tubing margins reached an all-time high, did they increase or decrease in Q4?

I am not sure. My guess really, we had again, across most of our service lines, including coiled tubing was impacted by the Holiday. So again, my guess is probably (inaudible) is likely.

Yeah, they decreased a bit, John, and that would just be lower utilization, you know, lower cost absorption. John Daniel - Simmons & Company: But that would be, that one would clearly probably be more seasonal than what’s going on in pressure pumping and the pricing issues?

More so, we believe, yes.

Yes, for sure.

(Operator Instructions) It appears there are no further questions. At this time, Mr. Landers I would like to turn the conference back to you for any additional or closing remarks sir.

Okay great. Well we appreciate everybody calling in and listening this morning. We appreciate your question and discussions. Everyone have a great day. Thank you.

This concludes today’s conference. Thank you for your participation. Today’s conference call will be replayed on our website within two hours following the completion of the call. Thank you.