Nabors Industries Ltd (NBR) 2010 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the First Quarter 2010 Superior Well Services, Inc. Earnings Conference Call. My name is Josh and I will be your coordinator for today. (Operator Instructions.) I would now like to turn the presentation over to our host for today's call, the Chairman and CEO, Dave Wallace. You may proceed, sir.

Thanks, Josh. Good morning, everyone, and welcome to the Superior Well Services First Quarter 2010 Conference Call. Joining me today is Tom Stoelk, our Chief Financial Officer. I'd like to remind all those participating on the call today that a replay of our conference call will be available to listen to through May 21 at 888-286-8010. The conference I.D. for the replay is 15330297. A replay will also be available on our website.

Before I begin with comments on our operating performance, I'd like to make the following disclaimer regarding our call today. Except for historical information, statements made in this presentation including those relating to acquisition or expansion opportunities, future earnings, cash flow, and capital expenditures, are forward looking statements within the meaning of Section 27-A of the Securities Act of 1933 and Section 21-E of the Securities Act of 1934. All statements other than statements of historical facts included in this presentation that address activities, events, or development that Superior expects, believes, or anticipates will or may occur in the future are forward-looking statements. These statements are based on certain assumptions made by Superior based on management's experience and perception of historical trend, current conditions, excepted future developments, and other factors that are believed appropriate in the circumstances. Such statements are subject to a number of assumptions, risks, and uncertainties, many of which are beyond Superior's control, which may cause Superior's actual results to differ materially from those implied or expressed by the forward-looking statements. These risks are detailed in Superior's Securities and Exchange Commission filings. The company undertakes no obligation to publicly update or review any forward looking statements.

Our call agenda is as follows. I will first provide an over view of our operation and turn the call over to Tom, who will review our financial results. After Tom's review, I'll provide some closing remarks and open up the call to Q&A. Activity levels in the first quarter continued to ramp up as our customers gained comfort with the outlook for oil and natural gas liquids producers in 2010 and continued to expand drilling in the natural gas shale plays. We experienced a 23% increase in activity levels compared to the previous quarter. As a percentage of gross revenue, average sales discounts across our service line decreased by 1.2% in the first quarter of 2010 compared to the previous quarter. We continue to see pricing improvements and lower discounts driven by increased utilization.

Our activity increase level and improved pricing drove our 29% sequential increase and net revenues to 123.3 million and a 9.6 million sequential increase and adjusted EBITDA to 10.4 million for the quarter. Stimulation revenues increased 29.2 million or 46% sequentially and represented 75% of our total revenues for the quarter. We anticipate the continued improvements in stimulation activity level and pricing will continue to be the main driver for our business in the near future.

Now, let's turn to the focus of our five operational regions. Our Appalachia service centers support the Marcellus, Huron, and other shale plays. We're currently running three stimulation crews in the Marcellus, which includes the utilization of crews from our mid-continent region. Revenues of 30 million from our Appalachian crews were down 14% sequentially, while revenues from our mid-con crews working in Appalachia of 9.5 million were up 184%. Total revenue as related to our Appalachian activities were 39.5 million, up 4% sequentially. Weather impacted our activity levels in the first quarter with cold temperatures, significant snow amounts and wet conditions. We have recently added personnel in the area, so we can--we worked to expand our 24 hour crew capabilities.

We also have the ability to move more of our resources into the Marcellus if the demand in pricing for our services warrants doing so. Our Marcellus sales team continues to make progress with new customers as we diversify our customer base and increase our Marcellus job count. Our sales team is successfully marketing our Optic Imaging System to our Marcellus customers. OptiB provides distinct well bore interpretation that is useful in optimizing fracture placement in horizontal shale wells and it recently won an award for engineering excellence from Hart Energy Publishing's E&P Magazine earlier this week at OTC in Houston.

We continue to fine tune our operational and logistical model as we move towards frac factory operations in the Marcellus given the geographic size, topography, material, and fluid requirements, and also logistical challenge. Our new Owego New York Cement Bulk Plant will be operational in the second quarter resulting in improved operating efficiencies. We remain focused on working with our customers to ensure that we can develop the play in the most profitable manner. Our strength in cementing work, combined with our job performance and our reputation for frac service quality helps us maintain our first mover advantage and strong competitive position in our backyard. We remain the conventional well leader in Appalachia.

In addition, our Michigan facility is strategically positioned to benefit from increased shale activity from existing and new potential shales. Revenues in the southwest region of 30.5 million increased significantly, up 79% sequentially. We expect the Permian rig count to continue to improve with high oil prices. We've increased our oily presence over the last two years with a focus on the Permian market. We anticipate entering the Eagleford shale play in the second quarter with work scheduled for one of our customers supported by our crews from existing service centers. Activity in the Barnett was also up in the quarter and our crews are positioned to cover work in the oily northern Barnett market.

Revenues in the southeast region of 22.4 million increased 38% sequentially. Our Haynesville technical sales team continues to demonstrate a proficiency in performing high quality completions in high pressure, high temperature down hole environments. We remain focused on providing high tech cementing and simulation solutions to existing and new customers that are required in this high pressure, high temperature play. We're also seeing a pickup of oily areas in Mississippi.

Revenue s from our mid-continent based crews of 23.8 million increased 28% sequentially with 9.5 million of this activity consisting of Marcellus work by our mid-con crews. We have historically been active in the Fayetteville and Woodford and are reviewing these markets as we look to optimize our pricing and overall returns. Our mid-con crews are well positioned to participate in the Granite Wash play in Texas and Oklahoma.

Revenues from the Rocky Mountain region of 16.7 million were up 80% sequentially. We have seen improvements in activity levels driven by increased oil and liquid focused activities. And our geographic footprint in the Rockies allows us to effectively compete for this business, including the Niobrara shale activity. The crew we established in the Bakken oil shale play in North Dakota, continues to gain significant traction and we're supporting additional Bakken activity with crews from our other Rockies location.

I'll now turn the call over to Tom for a review of our financial results.

Thanks, Dave. Revenues were 123.3 million for the first quarter of 2010, a 28.6% sequential increase. Revenues from our technical pumping services, which include stimulation, cementing, and nitrogen, accounted for 89% or 110 million of our total revenues. Down hole surveying services, completion services, and fluid logistics were responsible for 5%, 2%, and 4% of our revenues, respectively. On stronger activity levels, cost of revenues increased 17.1%, or 17.8 million for the first quarter of 2010, compared to the previous quarter. As a percentage of net revenue, cost of revenue decreased by 9.7% to 99% for the first quarter of 2010 from 108.7% for the previous quarter due primarily to decreases in material, labor expenses, outside contractors, and depreciation as a percentage of net revenue.

Material cost as a percentage of net revenue decreased by 3.9% in the first quarter of 2010 from 40.2% in the previous quarter due to lower sand and chemical costs and improved pricing. Labor expenses and outside contractors as a percentage of net revenues decreased by 2.5% to 20.5% in the first quarter of 2010 compared to 23% in the previous quarter due to improved utilization using fewer contract employees and improved pricing. Partially offsetting these improvements, repair costs as a percentage of net revenues increased by 1% due to higher equipment repairs from our shale based activities. Selling, general, and administrative expenses increased 3.9% or 400,000 for the first quarter of 2010 compared to the previous quarter. As a percentage of net revenue, SG&A expenses decreased by 2.2% to 9.5% for the first quarter of 2010 from 11.7% for the previous quarter due primarily from our ability to spread these costs over a larger revenue base. Adjusted EBITDA increased 9.6 million in the first quarter of 2010 compared to the previous quarter, and reached 10.4 million. At March 31, 2010, we had 100.6 million of working capital and total long term debt of 164.4 million with 83.5 million outstanding under our credit facility. Our credit facility matures in March 2013 and we are currently in compliance with all covenants under that facility as well as the indenture governing our second lien notes. In April, we received a 34.6 million federal income tax refund, which was used to repay a portion of our credit facility. Under the terms of the credit facility the receipt of the federal income tax refund reduced the credit facility's total capacity by 25 million to 75 million in April, and our availability increased to approximately 20 million.

In the second quarter of 2010, we're going to reflect a non-cash charge of approximately 300,000 for the write-down of deferred financing costs. In accordance with the accounting rules you're required to write off a portion of the deferred financing costs when a portion of your total capacity is reduced. If you take a look at--if we adjusted our March 31, 2010 debt levels for the 34.6 million refund, we would've had adjusted book--debt to book capitalization of approximately 29%. Working capital increased 1.7 million from 98.9 million at December 31, 2009 to 100.6 million at March 31, 2010, driven by increases in accounts receivable of 18.6 million, partially offset by an increase in accounts payable of 15 million.

For the first quarter of 2010, we made capital expenditures of approximately 5.4 million, primarily for maintenance on our existing equipment, and to a much lesser extent, the purchase of new or upgrade of existing equipment.

At this point, I'd like to turn the call back over to Dave for some additional comments.

Thanks, Tom. We built Superior Well Services into the fifth largest pressure pumper in the U.S. and we're actively working to improve our competitive position. We believe that our strengths of reliable equipment, high service quality, and technical expertise in the key unconventional shale plays, combine to help reduce risk and maximize return for our customers. On the commodity front, we remain bullish on the outlook for crude oil and natural gas liquids, and have focused on increasing our oil and liquids presence in the relevant activity areas. On the natural gas front, we remain cautious regarding the near term outlook given the current supply and demand imbalance. If natural gas prices remain at their current levels, we anticipate that natural gas directed activity levels will decline first in the conventional basin impending any impact on production levels; second, in the less economic shale plays. We believe the following factors will help offset activity declines from the less economic gas plays and drive continued demand for pressure pumping services - increased activity levels in the conventional oil and liquid plays; the development of new oil and liquid shale plays, which creates new additional demand for pressure pumping services; continued increases in frac intensity with more stages and longer laterals; increased rig efficiency resulting in shorter drilling times and lower well costs; and our customers' hedge positions and need to hold acreage through drilling and production.

We feel we are well positioned to benefit from these trends with our strong, broad geographic footprint and operations focused on the oil and liquid rich areas in all the major shale plays. Our plan to remain a strong competitor includes reposition employees and equipment to take advantage of areas with the highest margins within our broad geographic footprint; aggressively manage costs at all levels of the organization to align our cost structure with the realities of the current market environment; provide the highest levels of service quality and results to our diverse base of strong customers; and acquire new customers on the basis of competitively priced, high quality service; maintain our disciplined approach to managing liquidity and cash flow; strengthen our presence in the markets where we have a clear, competitive advantage in the plays with the most durable economics; prioritize capital investment to maintain the performance of our relatively new fleet; ensuring high levels of service quality, safety, and reliability; continue to innovate and build on our technological advantages; and maintain and strengthen our technical sales teams.

Our crews have built a quality reputation one job at a time. I'd like to thank all of our employees for the hard work, continued dedication, and professionalism. We added approximately 150 employees in the quarter, an 11% increase, and are up 23% from our 2009 lows as we look to continue to increase our activity levels. I would again like to mention that our primary focus is to return to profitability and generate positive cash flow. Ours is a cyclical business and we'll continue to make adjustments to position our people and assets with an eye towards making the most of the recovery.

This concludes our prepared remarks. I'll now turn the call over to Josh to help coordinate our Q&A session.

Thank you very much, sir. (Operator Instructions.) And our first question comes from the line of John Tasdemir from Canaccord Adams. John, you may proceed.

Hey. Good morning, guys. Just a couple of questions. One is, it sounds like there were some other issues in the quarter that you guys talked about on the last conference call actually. Can you help us get a sense of as we look into the second quarter maybe where utilization levels kind of were in the first quarter and are today? Just help us a little bit in terms of quantifying how much the weather might have impacted you?

When you look at our--where we had our equipment placed in first quarter, 50% of it would have been in what we call the seasonal areas between Appalachia and the Rocky Mountain region. We definitely saw the impact of winter and in January and February. Once things started loosening up weather wise, all the snow started melting, it got a little warmer, we saw activity take a nice ramp up I in March. And so we weren't at full utilization for the quarter. We did see again nice strong activity levels in March. And as we continued to stay out of the seasonal time periods, we expect activity to continue to increase.

So I guess another--given we don't have the weather excuse anymore, we'd expect another pretty nice tick up in top line as we look into the second quarter as--with better utilization? Is that--?

David Wallace. Yes. Again, like you say, we came out of the seasonal activity time period. We're seeing utilization still move upward in the right direction. Something we've done is we are focused on pricing versus utilization, so pricing first, utilization second, which may dampen our utilization just a little bit, because we feel like the market is where we still need to get some pricing power from where we are.

Okay. Well, that makes sense. So that kind of leads into my second question. I think you said that your pricing discounts - you had I think 1.2% last--in the first quarter over the fourth quarter. Can you give us a sense of where that might sit today?

It's still improving.

It's still trending in the right direction. And again, we're--when you look at some of this pricing we would have had contracts that we entered in '09. And part of that is it takes a little while to roll them off where you can move into new pricing arrangements. But the rig count's staying very strong. Activity levels continuing to be very high. We're getting a lot of calls to move equipment into different areas for different customers with better pricing. So we're looking at those and deciding how it's best for us to ship the resources.

Okay. Well, I guess what I was kind of getting at is, one is I wonder if we're going to see a better pricing impact in the second quarter--or a bigger pricing in the second quarter than we saw in the first quarter, and I'm wondering also if that means you ultimately get a better incremental margin in the second quarter than you might have saw in the first quarter.

I think that's probably--generally that's how we feel right now. In this market, the market's fairly dynamic. You get two or three months of pretty good visibility and after that it's hard to tell. You're just looking at trends. But generally we feel that way, that it continues to improve.

Okay. Thanks, guys. I'll turn it to someone else.

And our next question comes from the line of Bo McKenzie of Global Hunter. Bo, you may proceed.

Hey, guys. Weather in the Marcellus--we've talked about this before--tied up a lot of capacity from being able to move. Although the drilling rig count went up a little bit on the average Q1 to Q4. Is there any kind of sign of a build in backlog of work up there of wells that got drilled, but--encased, but not completed? And as--if there is, does that lead to a much stronger pricing environment as the visibility of work starts to extend out quite a bit?

I think that like you're saying it's very difficult to do the stimulation in the winter time. When you're moving that much fluid and the roads get that icy, again, people just back off on their completions. So I think Appalachia is an area that we can see a backlog, plus I think there's some other areas that we see backlogs as well. So again, rig counts continue to climb and there hasn't been that much pressure pumping equipment added. So the market's still tight and we feel like there's areas that we can continue to move pricing based on that.

Are we on the one question, one follow up question? Because if we are, then my next follow up is I've got a Canadian frac company that the head of sales is in my office complex and we're friends. And he's telling me that they're quoting work into July right now pretty much across the country. Do you guys see a similar kind of tightness in terms of capacities being allocated at some of these wells out there such that availability is quite some distance off for the next jobs?

We're still getting a lot of requests to try to lock us in for long periods of time, which says that the E&P guys all recognize there's a shortage on our--in our sector. We're a little bit hesitant to do that because again we feel like that pricing first, utilization second. And--but visibility right now looks like for the next several months it can be extremely busy.

All right. Am I allowed to ask one more? I know that there have been a couple of people that have been starting to order fracture equipment here and there. My friends up at [Twin Disk] have seen their backlog on the 8500 transmission stack out as big as it's ever been. You guys have done a good job of reducing some of the debt. As you start to take that adjusted debt to total capitalization down are there changes we could expect to see in terms of available liquidity such that should we go into an era where we've got really strong pricing and the ability to lock up some capacity on term, you'd be able to participate in any kind of additions to the fracs laid out there?

It's something that we've been able to manage so far. In some respects, it's a nice problem to have because you're--it generally means that there's an increase in activity levels. We continue to kind of monitor it. If the trends continue as strong as what we're seeing right now, and we do anticipate or actually experience those kind of increases, it's something that I'm sure we can sit down and work out with our banks. And I think as most individuals probably know on the call, under our current credit facility we're limited to 6 million a quarter. But with the strong activity levels that we're seeing, if those continue it will become challenging and at that time what our expectation is is in advance of that we'll sit down and work something out.

All right, great. Thanks. I'll turn it back over.

Thanks, Bo.

(Operator Instructions.) And our next question comes from the line of Victor Marchon of RBC Capital Markets. Victor, you may proceed.

Hi, Victor.

Victor, your line is open. You may proceed.

I apologize. I was on mute. Good morning, guys. The first question I have is just on utilization. I apologize if you touched on this earlier. But I believe back in March you guys had talked about excluding inclement weather in the first quarter that you were probably running a bit better than 60%. I wanted to see first if that was--if you guys hit that number in the first quarter and then where you sit today or where you see the average in the second quarter.

As you can tell from the revenue channel and especially on the stimulation side, a majority of that was driven by utilization. So we saw a higher utilization in first quarter versus fourth quarter and a lot of that was driven by March. I mean, March really got very active, again, once we started coming out of the winter season in some of our seasonal areas. And we feel like that again that higher utilization can be maintained during the second quarter. There'll be some adjustments to that just based on just logistics, especially in Appalachia, as some of these wells may slide around just due to not enough third party infrastructure that they can get ready in time or maybe there could be some delays due to--for political reasons in the area. But we see it trending in the right direction. And again, our focus is we still feel like it's a strong market that our pricing needs to improve. So we will focus on pricing first and again utilization second.

And that's where I was going with it is into how much more room on utilization do we need to go before you hit that inflection point on the pricing side? Are we within five percentage points, 10 percentage points? Just trying to gauge some of that.

Yes, five'ish, 10'ish, somewhere in there that we've increased. I think that again the mix is changing quite a bit also. And again, when you start going from 12-hour crews to 24-hour crews, some of the old utilization numbers change over what we've seen in the past. When we were a conventional company and basically were focused on catching a job a day, you used different utilization numbers than maybe what you use today. So the old numbers in today's environment we may look a lot higher utilization, but there's still potential upside as we continue to add people, refine our frac factory process where we can do more stages. Then we can continue to tweak that utilization up over previous levels that we've seen.

Thank you for that. And the second one was just as relates to your comments on the Marcellus and the Bakken where you could potentially move additional crews into those markets. The Bakken I guess would be from the Rockies, and on the Marcellus side, where would the crew likely be pulled in from? And I guess it's almost secondarily asking you on a regional basis which market or markets are you seeing any weakness in that you would use it as a source of equipment into stronger markets?

I think the biggest we're focused on is--we talked about it as far as may some of the dry gas areas, and conventional areas first. We feel like they could become a lot of pressure, that rig counts could slip in those areas. And so, some of the areas that are kind of seeing more of a dry gas area. But even those crews are probably fairly strategically located and close to even some liquid rich areas. So we're looking at basically margin comparisons between a lot of these different regions. And again, with the increase in the oily areas, we feel like that there is opportunity to shift resources to some of those. So maintaining the footprint during 2009 has proven to be a very good strategic move for us. As things ramped up this year, as you can see, looking at our Rockies activity, that was an area that was under a lot of pressure last year that has rebounded nicely. Same way with some of the other oily areas. So we're really focused on margins by each region. And we'll shift resources to the better spot.

Thank you. That's all I had.

Thanks, Victor.

And our next question comes from the line of William Conroy of Pritchard Capital. William, you may proceed.

Good morning, Dave. Tom, hello. I was hoping you could give maybe just a little bit more detail, put a little bit more color around what you're seeing in west Texas, and as well, your entry down into south Texas in the Eagleford.

The Eagleford is one that's been hot for quite a while. And when you look at the Permian, it's one that's had a really nice ramp up year over year. And one of the rigs that will be shifting from some of the drier gas areas, maybe Barnett, Fayetteville, some of the conventional areas, we see moving to those areas. So we're positioned quite well in the Permian. And as far as the Eagleford we have crews between the Barnett, Permian, Haynesville, that they're not readily close, but close enough where we can work for customers in that area and potentially start setting up a satellite location to expand our activities in those areas.

And a different question. Dave, can you give us a little bit more detail around how much 24-hour business you're doing today? I'd love to quote--for you to quote me a number. I'm guessing you won't do that.

Yes, that's correct. It would be less than half of our crews at this point. And it's one of the things that you kind of work your way back up to it. We talked about how much we've grown our labor force since we hit our bottom. And a large majority of that has been on the stimulation side. And you first get your crews maxed out utilization wise on 12-hour work then you slowly build that up to 24-hour work. And so it's a change for the service company, also a change for the E&P side that they have to build up their other third party support systems to handle those activities loads as well. But we can see there's several regions that we'll continue to build up to more 24-hour crews. And so, it's heading in the right direction.

Thanks very much.

And our next question comes from the line of Gabriele Sorbara of KeyBanc. Gabriel, you may proceed.

Good morning, guys. Can you discuss the oil gas split right now and where you can see yourself by year-end? Just trying to get a sense if you're going to become more oily in the near term.

Actually we continue to shift to oil areas. I mean, we see some gas areas that we feel like due to holding leases or just can work in maybe a softer gas price environment, like Marcellus and a couple of those areas, that we think they'll still maintain a fairly strong environment. But as you can see from our numbers, the Rockies is--there's a lot of oil activity there. Southwest region, heavy focus on the Permian. Again, getting more active in the Eagleford and even some of the other areas that we may consider gas, such as the Barnett. Again, we're positioned to handle activity in the oily part of the Barnett. You look at Oklahoma, which we've kind of considered more of a gas market. With the increase in the Granite Wash we're very well strategically positioned there. So it could be--we've talked in the past roughly 20% last quarter. It was probably actually higher than that when you look at some of the stuff we may have identified as gas was more really oily driven. And it's heading up 30, 40% pretty easy is the way it looks right now.

Great, thanks. And also, could you talk about your pricing discounts relative to the big three or the big two?

We don't want to give too much information there. I think that it really varies by each market. And if you get into some markets that are just short on equipment because everybody pulled out in 2009 and the rig count jumped in those areas, pricing is definitely better in those areas than some of the other mature markets where there's still a lot of competition. And one thing you see in this environment is when it really starts getting very busy, that service quality is more important than maybe having the lowest price. And we saw that shift really start to occur in fourth quarter when the market starting tightening up. You don't have to be--in certain situations be the lowest price guy. If you have good service quality, have available crews, and there's an opportunity that people need equipment, you can get a little better pricing. And I think that's one reason why, again, we kind of talk about that we see pricing as kind of more important than utilization right now, because there's some hot spots with our footprint where it is that we can reposition additional resources there and take advantage of those hot spots.

Great, thanks. That's all for now.

And our next question comes from the line of Shawn Boyd of Westcliff Capital Management. Shawn, you may proceed.

Good morning. How are you guys doing today?

Good, Shawn. How are you doing?

Very good. Just a couple of quick questions. Are we still at 430 of horsepower?

Yes, right in that ballpark.

Okay, very good. And going back to the comments about moving toward the liquids rich plays, Dave, can you help us think a little bit about what that does on your content, in other words, kind of revenue per well versus just dry gas?

It changes--the oily areas change the mix just a little bit. And what we see in the oily areas are they're still doing horizontals for the most part, and still doing long laterals, a lot of stages. What you may see is a little bit of job change and the rates may be a little bit lower. They may use thicker fluids. The proppants may change from a 40/70 dominant in the gas shales versus more of a 20/40, which is a little bigger and has a little more float capacity through it in the oil shale. So probably kind of the overall is a little less horsepower, a little more fluids, chemistry, sand change would be--but with that, the revenue stream can stay again very similar and it's based on again just a lot of stages and long laterals. But a little difference in how you get the revenue from it.

Okay. So the fact that it's a little bit less horsepower because you've got those other changes and you still have the long laterals, you're not necessarily seeing a decrease in revenue?

That's correct.

On a per well basis. Okay. And on the backlog, can you speak to that a little bit by region? It came up earlier, but maybe we could sort of talk about how big your backlogs are or what's the biggest backlog we're going to be seeing, which region and (inaudible).

I'm not sure we've got good visibility on all that. I think the thing that we see is where we're kind of getting the most requests and the highest demand for additional crews. And really that's in kind of a multi-region area. And again, we're kind of playing that to our strategy of focusing on price first, utilization second. For the right price we'll shift crews to various basins. And again, with our footprint we have some really talented crews that are capable of working in multi-basins. And our customers recognize that, and therefore we're getting a lot of requests to ship resources around.

Right. Dave, last question for me. Given how some of the bigger wells really abuse--really tear up the equipment, are you seeing that impact the competitive landscape at all? Are you seeing any smaller guys that are struggling because they can't meet the CapEx requirements, or is it changing the way you are kind of looking at the business here?

There's been several small guys that have been taken out of play here in the last year. And, again, it takes--I think the one thing that everybody sees is it takes more backup horsepower, additional blenders for each job, and you just have to factor that in. And I think that's one thing that helped speed up the tightness in the marketplace probably a lot faster than everybody anticipated. And it's pretty hard to--the first thing you do when you start getting really busy is you start saying, well, if I can pull a truck or two from here and there, why the next thing you know I can create another crew. And you get to the point where you just can't do that because you need the backup equipment. So it's definitely more equipment intensive, and tightened it up for everybody.

Very good. Thank you.

Thanks, Shawn.

And our next question comes from the line of Joe Hill of Tudor Pickering Holt. Joe, you may proceed.

Good morning.

Good morning, Joe.

Just to follow up on the last question, guys, if you don't get the CapEx requirement listed and spend another 6 million in the quarter, are you still going to have 430 workable--thousand workable horsepower at the end of the year or will it be something less than that?

We think it will still be that, Joe. Effectively, based on our internal forecast and kind of the view of the world that we kind of see now and it does change, we clearly have the capability of being able to maintain that fleet with existing cash flow requirements and availability under the facility, so the answer is yes.

Okay. And it sounds like you guys maybe feel a little bit better about your ability to drive incremental margins on a go forward basis given the pickup in activity and the reduction in discounts versus maybe where you felt on the fourth quarter call. Is that a correct assumption?

Yes, the trend's going in the right direction. And I think one thing we've talked about before that we've been a little cautious on gas prices. And if it was going to--again, coming out of a cold winter we saw very similar to last year and the rig count dropped quite a bit. I think this year that we're not seeing that. We're seeing maybe a few more rigs shift to oily areas, where again, we've had a pretty strong presence in some of those areas. So the impact of rig count staying up and just commodity prices holding in there. We feel a lot more positive than we have in the past.

Okay. And then, Tom, maybe if you would , could you give us some help on what your outlook is for SG&A, DD&A,

Taxes, probably 36, 37% effective rate for the year. DD&A I think will trend up. You take a look at our work in process and it will be kind of a timing thing, Joe. But at the end of the quarter, we had about 8.7 million of CIP, and depending on when it's placed in service, you'll see that trend up maybe next quarter by maybe 700,000, 800,000 and then get up to maybe about a million and be fairly flat in the fourth quarter with respect to that. SG&A, I think as a percentage of revenue, it will stay at or slightly less drop--slightly less from where it's at. The reason I say that is as part of our cost cutting efforts, in 2009 we discontinued the 401(k) match in April of this year, so it's not reflected in Q1. We reinstituted that match. What we did, was we reinstituted it with a match of our common stock, so it's going to be non-cash. But that's going to probably add about $500,000 a quarter to our numbers, not necessarily all SG&A, but the larger portion of it likely.

And in addition, Dave's--through our comments today, we've talked about an improving environment and kind of what at least with the visibility we have looks like a pretty good working environment for us. You're going to start to see some increases in some of our labor costs in connection with that, probably some in the form of incentive compensation, things like that that you haven't really seen in 2009 at all. So that's going to also have an impact. But I guess, I'm kind of looking at it as a percentage of revenues right now. But in the aggregate, those two numbers are probably--they could be a million--well, depending on the incentive comp element of it, range between $1 million and $1.5 million, if the numbers start trending the way we think they will.

Okay. Sounds good. Thanks a lot, guys.

You bet. Thanks.

And our next question comes from the line of Tom Hauser of Guggenheim Partners. Tom, you may proceed.

Hey, guys. Thanks for the call.

Hey, Tom.

The question, in terms of the updated liquidity position, pro forma for the tax refund, is it the 20 million on the revolver? Is that what I heard earlier?

Yes, yes. As far as availability?

Yes.

On a pro forma basis after--yes, we had about 10 million of availability at the end of the quarter. And we--the tax refund was I think 34.6 million, call it 35. The borrowing base or our capacity went down by 25 million, so it's simply the math of 10 million of excess cash on the refund plus the availability. That's how we're calculating it pro forma.

Okay, and then a pretty negligible cash balance?

Yes, a fairly negligible cash balance.

Okay. And then, following up on the previous two questions, what is--or what do you estimate is your actual maintenance CapEx for the year in dollars?

Yes. 20 million.

20 million?

Yes.

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

Okay. Thanks, Tom.

And our next question comes from the line of Bo McKenzie of Global Hunter. Bo, you may proceed.

Hey, guys. With the pick ups that you guys are seeing in some of the oilier areas, is there any kind of mix change that's occurring that would imply like a move towards more costly gel fracs, or are those going on as slick water fracs as well? I guess what I'm trying to get to is, if you look at the kind of margin differential between the more technical work versus the cross--the slick water fracs, are these job pushing that technology to where the chances of differentiating yourselves from some of the smaller players is occurring yet or not?

We're seeing in the oily areas again probably fewer slick water fracs, and then thicker fluid systems, a combination of just linear fields, and like you're saying cross links in certain areas. So there's definitely a change in the mix. And part of that is due to like a 20/40 sand is bigger than 40/70, so you need a thicker or more viscous fluid to help carry that bigger proppant.

Right.

So, yes, you're pretty well on track that the chemistry changes with the--it changes a little bit with the oily plays.

And Dave, if you go back and you look historically where you guys were doing more of the stuff where you were able to differentiate yourself from the technical expertise internally, you used to be a lot more profitable. Is there kind of any general commentary you could give us in terms of how these more complex jobs are being bid versus the slick waters that we've seen being the predominant form of the market for the last couple of years?

I think there's--again, we feel like the chemical change is right up our alley as far as we're technically challenged--challenging, which fits our background and our focus in the past. We also feel like it really kind of varies a little bit by region based on how much competition is in each of those areas. One thing we saw in 2009 is a lot of competition kind of retrenched in certain market areas that have now started to build back up. Maintaining a presence there has definitely been a plus that we're able to be a participant when that activity ramps up at hopefully better pricing. So I think the combination of the technology and being in some of these more active markets gives us that opportunity to continue to move pricing in the right direction.

All right. And then, kind of another, without having to point the finger in the blame game. But if you were to look at the guys that are smaller than you versus the guys that are bigger than you, do you notice anybody that's really holding back pricing amongst either of those two groups and trying to still fight for market share? Or is it fair to say that utilization is so full out right now across the bulk of the North American market, that there is just no market share jockeying left to be done and that the pricing behavior is pretty comparable amongst both the big integrateds as well as the smaller companies?

I think there's a couple of things there is-- some of the smaller guys, if they're just regionally focused, then they may not have the opportunity to shift resources maybe between better markets. So I think you're going to see something there. I think also again if you had some older contracts that you're still kind of working through, that you may not be able to participate in some of the upside in certain areas or shift resources.

Right.

But if the market continues to hold where it is and be tight, then we expect there's going to be continued pricing improvement in several areas.

Do you think that it's possible to get back to--on an apples to apples basis, of course, given the difference in the mix of the work, but the kind of 2007 pricing before the market started to get some overcapacity built up in it?

Yes. I mean, well, we'll have to see.

We can hope.

There's a big change from '07, '08 to current pricing, but it's working in the right direction.

Yes. All right, guys. Well, thanks. And congratulations on what looks like a pretty good quarter.

Thanks, Bo.

And our next question comes from the line of Andrea Sharkey of Gabelli and Company. Andrea, you may proceed.

Hi, good morning. How are you?

Good morning, Andrea.

Just a couple of questions. I think you mentioned in your prepared comments some of the question marks I guess on the Marcellus has to do with the environment issues. And I was just curious if you had any thoughts or updates to give us on that. I think I saw something a week or two ago in New York where the head of the DEC said he thinks drilling will start in the summer of next year. So any thoughts to that and how that could impact activity there and potentially a benefit for you guys?

We feel like Marcellus is a tremendous financial impact for all the states, along with just a great opportunity for the region. And it's just a matter of finding the right balance between all the different groups to continue the process. We feel like New York is one that has to look across the border and say, there's a whole lot of good things being generated in Pennsylvania and it's just a matter of when they want to participate. Our location that we put in Owego, New York is right on the Pennsylvania/New York border. And it's really very well positioned for what we except to be not only the activity going on in northeast Pennsylvania, but also the activity that somewhere in the future will take place in New York. So it's just--it's a culture change for a lot of the eastern Pennsylvania and New York area where they haven't seen oil and gas operations in the past. But there's a lot of benefits that come with the shale gas being produced. So there's going to be some delays, but overall, we feel like it's heading in the right direction.

Okay, great. And then, just one last question. I know you've heard some of your competitors talking about increasing capacity and at this point you guys aren't doing that. But do you think that has any potential to change the landscape? Does that allow them to either maybe take market share from you or on the other side maybe just hurt pricing, so you guys aren't able to push pricing as much? Or do you think the markets are tight enough that they can sort of absorb this additional capacity that might come out in the next nine months or so?

I think the markets are really tight. I think also when you look at capacity coming on, most of it's going to be 2011 versus 2010. So there wasn't really any new capacity added 2009 or really very little capacity come on in 2010. So we don't think it's going to have much of an impact on changing the competitive landscape. And we think it's going to stay tight for going on in the near future.

Okay, great. Thanks. That's all I had.

Thank you.

And our next question comes from the line of [A.J. Strasser] of Cooper Creek Partners. A.J., you may proceed.

Hey, guys, thanks for taking my questions. Great quarter there. A couple of questions. One is, kind of look at your '06, '07, 2008, and look at sort of how revenue kind of moved sequentially from Q1 to Q2 and so forth, I think it typically sort of moves up as we go through from quarter to quarter throughout the year. Any reason why we shouldn't kind of see your top line move in that direction? And my second question just on margins. Obviously, when looking back at you guys historically kind of in the 25% EBITDA margin range. And you're already kind of bumping up near 10%. And just based on some of the incrementals that you guys seem to be confident about, any reason why this can't be sort of a near term 20% or even better EBITDA margin story? Thank you.

We feel like it's heading in the right direction as far as, again, utilization can be as busy as you want it really in this environment. It's just a matter of pricing power, continuing to work through that. And the job makes us definitely different now than what we've seen in our '06,'07, '08 time period where this is more of a large volume slick water versus a lot more of the higher tech activity levels that we used to do at that time period. So there is a job mix and we talk about the frac factory where there's a lot of material handling, material costs in that. And that's just a matter of fine tuning our economics there and continuing to get some pricing power to go with it. But that's headed in the right direction as we see it today.

So could we expect to see kind of similar sequential increases throughout the year on a quarter by quarter basis on your top line? And again, just to kind of take it back, is a 20% margin doable at some point in the near future?

Yes. I think that it came off a 29% sequential increase. That's a pretty tough number to kind of fight against quarter in, quarter out. I do think that the activity is kind of getting stronger, so I think there'll be a decent sequential increase. One of the problems or one of the difficulties in kind of answering your question more directly is that our visibility is really two to three months and there's a lot of dynamics kind of going on. But I think in Q2 we feel pretty good about that, putting up another 29% sequential increase. We're not saying it's not possible, but it would be challenging, I think. I do think that with the increase--top line increase, I think to your point about it will have a favorable impact with respect to the EBITDA margin, 20% near term probably very, very challenging and maybe not so likely. But I think that as you continue to see us come out of the--David commented in the text in a lot of the Q&A here with respect to the seasonality in Appalachia. And we had a strong March, looks like a very strong April as well. So those are all really, really good signs with respect to that. But 20% on EBITDA, yes, that's pretty challenging.

Is that margin something you think you can see kind of six months out in the 2011 timeframe?

I think it's something you'll continue to see. David referenced in his comments about number one, trying to move pricing, and then, number two, trying to use--move utilization. And to get to those type of numbers you're going to have to continue to see the sort of pricing movement that we started to see sequentially from Q4 to Q1. And if it remains as strong and trends as strong, it's possible. But like I say, the reason you're hearing us being a little cautionary is that we have two to three months of really what we think are pretty good visibility, and then after that, we're just like everybody else. It's pretty dynamic in the jumps even in March were pretty large compared to the first couple of months. So it's just hard to go off of some very limited data points. I'm trying not be evasive and tell you what we know. But I wouldn't press you in that direction.

Thanks a lot.

Thank you.

And at this time, we are showing no further audio questions available. Dave Wallace, you may proceed.

Great, thanks. We appreciate your interest in Superior and we look forward to talking to you next quarter. Thank you.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Have a great day.