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Superior Energy Services (NYSE:SPN)

Q2 2012 Earnings Call

July 31, 2012 11:00 am ET

Executives

Greg A. Rosenstein - Executive Vice President of Investor Relations & Corporate Development and Member of Administrative Committee

David D. Dunlap - Chief Executive Officer, President and Director

Robert S. Taylor - Chief Financial Officer, Principal Accounting Officer, Executive Vice President and Treasurer

Analysts

Kurt Hallead - RBC Capital Markets, LLC, Research Division

James C. West - Barclays Capital, Research Division

Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Marshall Adkins

Matthew D. Conlan - Wells Fargo Securities, LLC, Research Division

Michael R. Marino - Stephens Inc., Research Division

Daniel J. Burke - Johnson Rice & Company, L.L.C., Research Division

Robin E. Shoemaker - Citigroup Inc, Research Division

Jeffrey Spittel - Global Hunter Securities, LLC, Research Division

Stephen D. Gengaro - Sterne Agee & Leach Inc., Research Division

John M. Daniel - Simmons & Company International, Research Division

Operator

Good day, ladies and gentlemen, thank you for standing by. Welcome to the Superior Energy Services Second Quarter Earnings Conference Call. [Operator Instructions] This conference is being recorded today, Tuesday, July 31, 2012. I would now like to turn the conference over to Mr. Greg Rosenstein, Executive Vice President of Investor Relations and Corporate Development. Please go ahead, sir.

Greg A. Rosenstein

Okay. Good morning, and thank you for joining today's call. Joining me today are Superior's President and CEO, David Dunlap; and Chief Financial Officer, Robert Taylor.

Let me remind everyone that during the call today, management will make forward-looking statements regarding future expectations about the company's business, management plans for future operations or similar matters. The company's actual results could differ materially due to several important factors, including those described in the company's filings with the Securities and Exchange Commission.

During this call, management will refer to non-GAAP financial measures, including EBITDA and adjusted net income from continuing operations. And in accordance with Regulation G, the company provides a reconciliation of these non-GAAP financial measures on its website. With that, I'll now turn the call over to David Dunlap.

David D. Dunlap

Thank you, Greg, and good morning, everyone. We reported quarterly revenue of $1.2 billion, EBITDA of $375 million and adjusted net income from continuing operations of $131.6 million or $0.83 per diluted share. We had an excellent quarter despite a challenging U.S. land market in which we performed very well. Our U.S. land revenue increased 37% over the first quarter, primarily due to the full quarter contribution from Complete. If we assume Complete contributed a full quarter in Q1, then our U.S. land revenue would've been essentially unchanged.

Strength in pressure pumping and downhole drilling tools was offset by a decline in intervention services such as coil tubing and wireline and accommodation rentals, primarily in the dry gas basins.

On a full quarter basis, pressure pumping revenue increased over the first quarter by 6%, while the operating margin was slightly higher. This is partly attributable to our contracted horizontal well factory model in which 11 of our 18 fleets are on 3-year term contracts with minimal exposure to guar pricing and other fluctuations in raw material prices.

Our downhole rental tools comprised of premium drill pipe and bottomhole assemblies also showed strength in the U.S., experiencing revenue growth of 2% despite a 1% decline in U.S. rig count. These businesses are leveraged to the horizontal rig count in oily areas.

Lower coil tubing, wireline and accommodations revenue was largely a function of reduced demand in the dry gas basin where we finally worked through the completions backlog after several quarters of high demand despite months of falling rig activity. To a lesser extent, we also experienced some weakness in the Bakken as the mild winter led many customers to drilling complete wells earlier in the year than they anticipated.

The Gulf of Mexico and international markets showed the strongest growth in the second quarter. Gulf of Mexico revenue increased 12% due to a 20% increase in revenue from the Drilling Products and Services Segment. Much of this growth came from the deepwater as the rig count reached post-Macondo highs. International revenue increased 11% due to a 15% increase in revenue from the Subsea and Well Enhancement Segment. Much of the increase is attributable to well control projects and other pressure control work performed in the North Sea, West Africa and Middle East.

Through the first 6 months of this year, our results validate our diversified business model. We have met or exceeded our guidance without adjusting expectations downward during the period, maintained our overall margins, grew revenue and margins in pressure pumping, offset declines in certain dry gas basins in the U.S. land market with growth in the Gulf of Mexico and international markets and continued to integrate Superior and Complete.

After Robert walks you through some of the financial details of the quarter, I will discuss our guidance and outlook. And with that, I'll turn the call over to Robert Taylor.

Robert S. Taylor

Thank you, Dave. As we go through each segment, I'll make comparisons to the first quarter of 2012. As you know, the major content difference is the legacy Complete contributed a full quarter of results in Q2 as compared with a partial quarter in Q1. All of Complete's results are recorded in the Subsea and Well Enhancement Segment.

In the Subsea and Well Enhancement Segment, revenue was $1 billion, and income from operations was $180 million. U.S. land revenue in this segment increased 44% to $793 million. In addition to growth in the product line, as Dave mentioned, we saw increases in pressure control, completion tools and remedial pumping services.

In Gulf of Mexico, revenue increased 8% to $110 million. Plug and abandonment experienced a seasonal recovery in the second quarter, while we also saw an uptick in decommissioning and well control work.

International revenue was $142 million, which represents a 15% increase from the first quarter. As Dave mentioned, Wild Well Control successfully completed several emergency response projects. In addition, we had a full quarter contribution from Complete's coil tubing business in Mexico.

Our operating margin increased about 260 basis points over the first quarter when you exclude transaction-related expenses from Q1. The margin growth was due to improved margin performance from pressure pumping and well control -- 2 of the larger product lines in this segment, in addition to higher margins for some of our Gulf of Mexico services due to seasonal improvement from the first quarter.

In the Drilling Products and Services Segment, revenue was $198 million, and income from operations was $59 million, which represents a 5% sequential increase in revenue and a 4% sequential increase in income from operation. Gulf of Mexico revenue was $61 million, a 20% increase from the first quarter as the post-Macondo rig count continues to outpace our expectations. International and U.S. land revenue was essentially unchanged from first quarter level. As Dave mentioned, the key takeaways from the U.S. land market was a 2% increase in downhole drilling tools, which was offset by a decline in accommodation.

Turning to the balance sheet. At the end of the second quarter, our debt was $2 billion. Debt to EBITDA at the end of the quarter was 1.6x as compared to 1.7x at the end of the first quarter, and debt to total capital was 33%. We currently have nothing drawn on our $600 million revolver.

Capital expenditures in the second quarter were $315 million. For the first 6 months of the year, capital expenditures were $588 million.

From a modeling perspective, in the third quarter, we think you should model G&A in a range of $155 million to $160 million. For DD&A, we think you should model a range of $140 million to $145 million. We anticipate net interest expense to be in the range of $30 million to $32 million. Weighted average share count is approximately 159 million.

I will now turn the call back over to Dave, who will discuss our earnings guidance and outlook for the year.

David D. Dunlap

Thank you, Robert. As we mentioned in the earnings release, guidance for 2012 has been reduced to a range of $2.75 to $3.05. That implies a midpoint of $1.37 for the second half of the year, which we think is about evenly distributed between the 2 quarters.

We often talk about how our diversified business model can reduce volatility in earnings. Clearly, we have experienced the benefit of this model during the first 6 months of the year. I believe our margins have held up better than many of our competitors while meeting or exceeding expectations in both quarters. The rationale for our reduced earnings guidance and outlook for the remainder of this year is driven by a variety of factors facing our U.S. land-based customers.

Our customers' cash flow has been negatively impacted by continued low natural gas prices, lower oil prices realized during the second quarter and by the precipitous decline in NGL prices. In this lower pricing and reduced cash flow environment, lower cash generation will stress and, in some cases, not support current budgets. As a result, we think customers can choose 1 of 3 scenarios: First, they can finish off their budgets at the current pace and then release their supply chain. Second, they can slow down the pace of work to stay within budget, working their supply chain at reduced levels. Or third, they can seek outside financing to maintain the current pace of activity once their budgets are spent.

During the past couple of years, many customers, particularly those in the horizontal well fracturing markets, would take advantage of improvements in drilling and completion efficiency and increased cash flows to fast forward their spending plans as they completed budgeted projects ahead of schedule in order to keep the supply chain working. We think this year that some customers will release their supply chain of rigs, frac fleets and coil tubing units when they hit their capital spending budget limits. Others will look for ways to slow down their spending. For instance, moving from 7-day schedules to 5-day schedules. In either case, the impact will be lower utilization.

Although the possible market scenarios will put some downward pressure on U.S. service activity, the outcome feels more like a soft landing, as to this point many of our customers have been reluctant to give up their supply chain, choosing instead to work services at lower utilization levels.

Not every component of our U.S. land business will react the same way in the next few quarters. For instance, we expect downhole drilling rentals and well service rigs to remain busy and expect margins in these services to hold up to Q2 performance levels. Coil tubing and fluid management will likely contract. Pressure pumping revenue will decline with lower utilization, but margins will hold within 400 basis points of Q2 margins as the bulk of our utilization is protected by the term contracting scheme in that business.

In dry gas markets, we think activity has nearly bottomed. There may be some small pockets of pricing utilization declines to go, but we are largely at the trough. These factors are driving our decision to reduce guidance for the remainder of the year. We think the Gulf of Mexico will remain strong and continue to improve from second quarter levels. We have underestimated the recovery in the deepwater as the rig count has surpassed our expectations throughout the year, so there could be additional upside in the Gulf.

International should continue to be a steady contributor. We are earning in our share of contract awards in markets like Brazil, while ramping up activity in new markets like Saudi Arabia. We are maintaining our current capital expenditure guidance of $1 billion to $1.1 billion, although CapEx will be winding down as the year progresses and could finish the year under $1 billion.

While we've not gone through our budgeting process yet for 2013, I would expect next year's CapEx will be lower by as much as 40%. Growth CapEx in 2013 will go to international and Gulf of Mexico markets. I expect that our U.S. services business would spend only at a maintenance capital level. This is very preliminary thinking as this point as our budgeting process will not be finalized until the end of the year.

I should comment that our near-term expectations from the U.S. land market represent a pause, not a long-term change in our outlook. We believe that as we enter 2013, our customers will adjust their budgets to reflect the kind of efficiency improvements that have been realized in the unconventional resource basins, that improved takeaway on oil and NGL will provide more certainty in cash flow and the U.S. independent customer base will continue to exploit underdeveloped oil opportunities resulting in an upward migration of drilling and completion activity.

That concludes our prepared comments, so we'll open the line up for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question is from the line of Kurt Hallead with RBC Capital Markets.

Kurt Hallead - RBC Capital Markets, LLC, Research Division

Dave, the, I guess, question I have for you is, what kind of sensitivity are you using in the context of rig activity for that reduced guidance? I know you mentioned the land drilling kind of being a pause. You went through the different scenarios and the what E&P customers may or may not do and kind of what your initial experience on those scenarios -- on those outcomes may be. I'm just kind of curious in terms of -- a number of your competitors are maybe suggesting kind of a flat rig count and some are suggesting it might be down, and I'm just wondering if you might give us a little range of what you think U.S. land-related rig activity might do between now and, let's say, year end or first part of 2013?

David D. Dunlap

I think between now and year end, it's probably got a slight downward pull, call it in a range of 50 to 100 rigs.

Kurt Hallead - RBC Capital Markets, LLC, Research Division

Okay. And do you think that the bulk of that -- and for your planning purposes at this point, do you think that's going to be the extent of the downturn and that first half would kind of exit flat with the fourth quarter?

David D. Dunlap

Yes, I think so. I mean, I think in the -- if we assume flat commodity prices with where we are today, that going into 2013 there may still be somewhat of a downward pull. But it's fairly muted. And you think about 50 to 100 rigs in a 2,000-rig environment, I mean, that's not a lot of activity change.

Kurt Hallead - RBC Capital Markets, LLC, Research Division

Yes. And then the -- I guess, my follow-up question will be what you mentioned on pressure pumping, the utilization levels coming down and I think you said margins will be within a few hundred basis points of the second quarter level. Can you just give us an update again as to what percent of your horsepower is contracted, when those contracts run out and then what you're seeing in the spot pricing market at this point?

David D. Dunlap

Yes. 11 of the 18 fleets that we have working in the field today are contracted on the term take-or-pay-type contracts and the first of those contracts expires in the summer of 2013 and that kind of run off over a 3-year period after that. We had some that actually started up in the first quarter of 2012 so, obviously, those don't expire until 2015.

Kurt Hallead - RBC Capital Markets, LLC, Research Division

What would that represent in terms of your overall horsepower?

David D. Dunlap

About 60%.

Kurt Hallead - RBC Capital Markets, LLC, Research Division

And then what have you seen with respect to spot pricing as we've kind of entered the third quarter here?

David D. Dunlap

Yes. I mean, spot pricing and more importantly, the -- just demand for spot fleets has certainly reduced significantly in the dry gas basins, and you do see some pricing pressure and utilization pressure in some of the oil basins as we've seen capacity migrate from the gas basins to the oil basins, and we've seen some new capacity coming to the market.

Operator

Our next question is from the line of James West with Barclays.

James C. West - Barclays Capital, Research Division

Quick question on your near-term guidance. If I just take the low end of your range, that would imply in a low 60s per quarter 3Q and 4Q, yet it looks like in the second quarter you're doing about $0.27, $0.28 per month here. Have you -- did you see a steady slide kind of in 2Q in your earnings profile that we get to those levels? Or are you building in just conservatism and seasonality and expecting more of a drop-off?

David D. Dunlap

Yes. I mean, we did see some downward progression during the course of the quarter and it was probably most pronounced in June. And as we talk to the operations and talk to customers and begin to understand it a bit more, I think it helped us to form our thoughts. Month of June helped us to form our thoughts on what we could expect for the rest of the year.

James C. West - Barclays Capital, Research Division

Okay, okay, fair enough. And then if we look a little bit longer term, I know you didn't give earnings guidance for next year but you talked a little bit about CapEx, how do we marry kind of your thoughts that the independents will become a little more active next year versus the idea that you might move down to more of a maintenance CapEx level on your U.S. land operations?

David D. Dunlap

Yes. So we've got equipment deliveries which are taking place during 2012, which we think are going to satisfy demand increase that we would experience during 2013. And so I guess what it says, and I think you've heard this from other people as well, we've talked about having some having frac fleets in some of the dry gas basins that we chose to park as opposed to move to the oily areas, and we look at that as dry powder.

James C. West - Barclays Capital, Research Division

Okay, okay. So presumably then, you'll be kicking off some free cash flow next year?

David D. Dunlap

Yes, we certainly think so. And of course, we haven't put together our full budget for 2013. When we do that, we'll be talking to you guys about it, but I think that's a pretty reasonable expectation.

James C. West - Barclays Capital, Research Division

Do you have any initial thoughts on kind of uses of free cash flow?

David D. Dunlap

Well, we're in conversation with our board about this. I think we've been pretty upfront in stating that our first use of free cash would be to retire debt. We've got $300 million in 6 7/8% notes, which are available to us at par, and that's kind of the first priority. And after that, we'll be having conversations with our board about other uses of free cash. And at the top of our list of discussion is what's the most efficient way to get that cash back to shareholders. We really don't have any other big slugs of debt to retire over the next couple of years. So that's part of our conversation at this point.

James C. West - Barclays Capital, Research Division

So share buyback is definitely on the table?

David D. Dunlap

Yes. I think that's part of the conversation we're having with the board. We currently don't have an authorization for share buyback. But as we look out to 2013, it becomes a bit more of an issue for us. It's not right now. The priority is buying in some of the debt.

Operator

Our next question is from the line of Joe Hill with Tudor, Pickering, Holt & Co.

Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

If I think about your coil, wireline and accommodations businesses as a bucket, how much of those are in dry gas basins at this point?

David D. Dunlap

I'm going to -- I don't have a perfect number sitting in front of me, Joe, but I'm going to say that it mirrors kind of the rest of our overall U.S. revenue mix, which would be on the order of 25%.

Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. And then if I think about the good well control work you had in the second quarter, is there -- is some of that continuing into the third quarter? Or we pretty much wrapped that up?

David D. Dunlap

Well, the thing about emergency response well control work, you'll never know when it's going to pop up. We do have periods where we get busier with that type of work than others. Let's say, Q2 is a pretty busy period for us from a well control standpoint, but we could be at 100% utilization next week, too.

Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay, so it's just too volatile to tell?

David D. Dunlap

Yes.

Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And then finally, how much longer can the upswing we've seen in the P&A and decommissioning business in the Gulf of Mexico last in your opinion?

David D. Dunlap

Yes. I don't know that it's been a significant upswing overall from a market standpoint. I mean, it's been a strong part of the business on the P&A side for the last couple of years. This year is a bit of an uptick for us on the decommissioning side, but it's a relatively small piece of our overall business. It -- there's still a lot of wells that are out there and a lot of structures that exist in the Gulf of Mexico that our operators are having to deal with, and we really don't see any kind of downturn in the available market over the next several years.

Operator

Our next question is from the line of Marshall Adkins with Raymond James.

Marshall Adkins

You gave a pretty good overview bridging us from the first half to the second half, but you went really fast. So I'm going to ask you to give us a little more color on it. I believe you said Gulf of Mexico, rentals, international holding up pretty well, coil tubing, pressure pumping down. I presume you've got to be assuming the well control stuff comes down from a pretty robust quarter as well. But just give us a little more color on that, if you could, and do it a little more slowly.

David D. Dunlap

I thought you did a pretty good job right there. I think that's fairly in line with our expectation. And the well control work is a bit difficult to forecast, as I'm sure you guys can appreciate, and Q2 was a good quarter for us on the well control business. But we got other parts of the product line as well that have the opportunity, I think, to improve during the course of the year outside of the U.S. business, and I can get back to clarifying our position on some of these product lines in the U.S. But things for us, like the subsea construction business which has still been relative underperformer for us, we think has got opportunities over the course of the next really 6 to 8 quarters to be an improver. We think that our completions activity in the Gulf of Mexico will really begin to step up more as we've doing more. We've seen more rigs that have been on a drilling cycle on the deepwater side and have not seen a lot of completions going on, and that begins to change in Q4 and into 2013. So that's a lot of different moving parts and pieces, I guess. The U.S. land piece is one where I think kind of consistent with the comments that I made before. Our expectation really revolves more around what lower utilization in the second half of the year than what we've experienced in the first half of the year in pressure pumping, coil tubing, accommodations and electric line and those businesses, whereas we see things like rental tools, downhole rental tools holding up pretty well as a result of what is still a market that's in great demand for those products.

Marshall Adkins

All right. A follow-up on that. You -- going back 6 months to a year ago, you're probably one of the better prognosticators on the Gulf of Mexico rig count. You ended up being pretty damn close as I remember it. What's your outlook now for the rest of this year and next year for Gulf of Mexico rig count?

David D. Dunlap

I think it's got an upward bias to it overall. I mean, we were very accurate with our expectations in 2011, and we've been probably a little on the low side from an actual versus expectation standpoint in 2012. I did not think that we'd get back up to pre-Macondo levels until the end of the year, and we're pretty close to those levels right now. There still seems to be a tremendous demand from our deepwater customer base to get more rigs into the market and pursue some of the very lucrative deepwater projects that they have. In the last few months, permits have been going our way which has been encouraging, although it's hard to base a lot of optimism on permitting activity, but it looks pretty strong, Marshall. I mean, demand seems to be good. It's been good on the shelf with more oily related projects. So overall, I think that rig count activity has generally a pretty good upward bias to it.

Operator

Our next question is from the line of Matt Conlan with Wells Fargo.

Matthew D. Conlan - Wells Fargo Securities, LLC, Research Division

I wanted to follow up also on the Gulf of Mexico. In this new post-Macondo environment, are you seeing uptick in the deepwater on revenue per rig? And if so, what are the product lines that are becoming more intensive for the new drilling?

David D. Dunlap

Yes. Well, for us, it certainly is an uptick in that we've got more exposure to revenue on a deepwater rig today than we did pre-Macondo. And that's primarily as a result of the acquisition of the completion tools business that we made in August of 2010. We think, overall, our exposure in the deepwater market is about 50% higher today than it was pre-Macondo. So that's certainly an uplift for us. And the traditional product lines that we've had in the deepwater arena on rental tools, I'd say it's been about flat with pre-Macondo, maybe with a slight upward tick to it, but overall flat on the rental tool side. You may recall we had exposure on 31 of the 33 rigs that we're drilling prior to the Macondo incident. So our share was pretty good and we're maintaining that pretty good share.

Matthew D. Conlan - Wells Fargo Securities, LLC, Research Division

Okay, great. And then just shifting back onshore. You're still expecting pretty big slug of new capacity of pressure pumping equipment coming out in the second half of the year, about 100,000 horsepower or so. What are your intentions for that? Are you going to put it out on the field? Or are you going to stack it, put it on the sidelines? What are your intentions for that additional capacity in this market?

David D. Dunlap

Well, we'll be opportunistic with that capacity where we see that it can deliver margins that are similar to what that business delivers for us today. If we can't operate that capacity at margins that are consistent with what we've seen in pressure pumping recently, then we'll park it.

Matthew D. Conlan - Wells Fargo Securities, LLC, Research Division

When do you have to make those decisions? Is it a real-time decision? Or do you have to make it ahead of time to get all the blenders and the other ancillary equipment?

David D. Dunlap

No. The equipment deliveries will be the same, whether we choose to put it to work or not. The lead time would be in sourcing the crews necessary for the incremental equipment addition. And those are clearly decisions that don't need to be made before the equipment is delivered. In some cases, they may be if the opportunities there, but they don't need to be.

Operator

Our next question is from the line of Michael Marino with Stephens.

Michael R. Marino - Stephens Inc., Research Division

A question on -- you mentioned the guidance expectations for kind of evenly distributed in the back -- in the second half of the year. I just want to understand, is that kind of maybe some seasonality in the Gulf being offset by international ramp? Or things will just kind of move sideways across all your geographic regions?

David D. Dunlap

No. As much as anything, we have historically had more of our overall exposure in the Gulf of Mexico as a company, which Gulf of Mexico there is some seasonality that typically we see a bit of in Q4 and even more of in Q1. And I guess as much as anything, with the growth in the company, our expansion in the U.S. land and expanding international business, it's just quite a bit more muted in our results today than it has been in the past. In Q4, it's typically a bit soft on the intervention and end-of-life-type services in the Gulf of Mexico. Q1 is one where we typically would see the more softness though. I guess as much as anything, Michael, the expansion of the company mutes that seasonality.

Michael R. Marino - Stephens Inc., Research Division

Okay, that's helpful. And just another one on the Compact Semi-Submersible. What's kind of the outlook for that upon, I guess, it's -- and when is it ready to work? Early next year, I believe?

David D. Dunlap

Yes. I think we've got -- I think that we're counting on revenue and earnings from the Compact Semi-Submersible in the second quarter of 2013. It'll be delivered to us sometime around the end of the year, early in Q1. And we've not been too rambunctious about planning when revenue comes in, but I can tell you that there a lot of customers that are looking at that vessel now, very interested in its capabilities. It's a -- it is, of course, quite a unique vessel and offers some unique opportunities for our customers, particularly in the Asia-Pacific area.

Operator

Our next question is from the line of Daniel Burke, Johnson Rice.

Daniel J. Burke - Johnson Rice & Company, L.L.C., Research Division

A question really following up on Michael's then in looking at the thought that your EPS in the second half of the year will be pretty evenly distributed. Does that also mean that in the North America onshore environment, you see margins pretty consistent in Q3 and into Q4? That the margin trend will be pretty flat in that second half of the year?

David D. Dunlap

Yes, that's generally a good expectation, I think.

Daniel J. Burke - Johnson Rice & Company, L.L.C., Research Division

Okay. And then, I guess, just to tie that thought together then. You ran an onshore top-line pro forma for CTX flat Q1 to Q2. You added a lot of capacity first half of the year. You talked about a couple of different business lines having different dynamics in the second half of the year. Stir them all together is again pretty flat onshore top line the right place to mark?

David D. Dunlap

No. I mean -- I think that with lower utilization, we'll see a little bit less revenue going forward from Q2. It's not -- this is not just a function of price. It's a function of utilization as well, and that will affect your top line number.

Daniel J. Burke - Johnson Rice & Company, L.L.C., Research Division

Okay, that's helpful. And then just to squeeze in maybe a last one there. In and around the timing of the closure of the merger, you all did some -- there were some portfolio actions. Obviously, the market now is a little bit more uncertain. But asset sales or product line rationalizations, any of that to expect here in the second half of the year?

David D. Dunlap

Nothing that's on the table at this point. I think we've been consistent in our message here that as we see parts of the business that are not attracting capital, then we'll look at those parts of the business for divestiture. And I think what we did with our liftboat business this year is a demonstration of how we carry that out. But there's not anything that's teed up of any size or substance at this point.

Operator

Our next question is from the line of Robin Shoemaker with Citi.

Robin E. Shoemaker - Citigroup Inc, Research Division

I wanted to ask you, what is the number of coil tubing units that you're marketing now? Is it 70? Or is it higher than that?

David D. Dunlap

No. We've got roughly 85 to 90 in the fleet at this point.

Robin E. Shoemaker - Citigroup Inc, Research Division

Okay. And that's with the additions you made?

David D. Dunlap

Yes. We've had a few additions in the first part of this year. The basis of that -- those are combination of the Superior and Complete fleets, which I think at close was at 84.

Robin E. Shoemaker - Citigroup Inc, Research Division

Right, right. And so then, your -- the contractual arrangements that you have on those are kind of call-out spot-related work. So have they kind of all repriced to the current market environment?

David D. Dunlap

I don't know that all of them have repriced. I mean, it kind of depends on the market they're working in. And of course, I don't want to represent those arrangements as being the types of contracts that we have on our term contracted frac fleets. They tend to be a much shorter duration. So some of those are essentially on call-out. Others are committed to customers for periods of time, on a monthly basis or what it might be -- whatever it might be. And so there's not really a generalization regarding price or utilization that I could put on that part of the business. It's been under pressure from a pricing utilization standpoint in the dry gas basins, and our expectation going forward is that with additional capacity that's come into the oil markets, it'll be under some pressure in the second half of the year once again for utilization.

Robin E. Shoemaker - Citigroup Inc, Research Division

I see, okay. Well, I also wanted to ask you about the fluids management business that you acquired with Complete and how that business is holding up in the -- in this time where we're seeing a drop in completions, well completions.

David D. Dunlap

Yes. Well, I mean, to this point, it's held up quite well. Our position in that business and our exposure in that business is largely in the oily basins. We didn't have dry gas exposure to any great extent with extent with fluids, so we've not really experienced much in the way of contraction at this point. I think our general belief is that as the year goes on with some contraction of overall drilling and completion activity that utilization and margins in that business will be under bit of pressure. But we think that, that is a slight contraction in revenue with maybe 300 or 400 basis points overall margin contraction. So it's kind of fits my overall theme for North American -- our North American services business, kind of a soft landing.

Robin E. Shoemaker - Citigroup Inc, Research Division

Okay. And just on that same business, is the production fluids management business stitched that is a logical extension of what you're doing with that?

David D. Dunlap

Well, I mean, produced water is a big part of that business for us today. And in fact, it's certainly a part of the business that we don't expect to see a decline in the second half of the year. That's a part of the business that holds up fairly well. So many of the oil and liquids-rich basins, which are being exploited by our customers today, are producing a lot of water. And so that keeps that business holding up fairly well.

Operator

Our next question is from the line of Jeffrey Spittel with Global Hunter Securities.

Jeffrey Spittel - Global Hunter Securities, LLC, Research Division

I guess, with regard to mobilizing equipment with a lot of the moves from basin to basin that's happened from an operator standpoint in the first half of the year, how far along are we in terms of being in the late innings with regard to your equipment?

David D. Dunlap

Well, we didn't have a whole lot of equipment migration. I mean, if you recall our fracturing fleets in the gas basin, really, we're exposed in the Marcellus. We didn't have any fracturing capacity in the Haynesville. We did have some coil tubing and some pressure control equipment in the Haynesville that we've been migrating out of there over the course of the last couple of years. We've been waiting for that completions activity in the Haynesville to slow down and really are only just now beginning to see a lot of impact from that as we work through that completions backlog. But I would say, overall, that we've not been quite as exposed to the costs and inefficiencies that go along with the equipment movements that many of our competitors have talked about. And perhaps that's part of the reason why our first and second quarter results have held up so well, at least part of it.

Jeffrey Spittel - Global Hunter Securities, LLC, Research Division

And shifting back to the Gulf of Mexico. You got, obviously, some inbound floaters headed for that market here over the next several quarters. As you look out into 2013 and maybe allocating some more growth capital to that end of the business, is there anything in particular from a product or service line standpoint that's at the top of your wish list in terms of devoting incremental capital?

David D. Dunlap

Yes. It's downhole rental tools, which we would expect to have some capital requirements for in 2013 as that deepwater rig fleet expands. We -- you may recall that when the moratorium was placed on drilling in the Gulf of Mexico, we took that opportunity to transfer out some of the rental tool assets, which were, of course, not being utilized at all and send those assets to international markets or U.S. land markets as appropriate. We've had to, over the course of 2011 and 2012, rebuild that rental fleet back up to accommodate current demand. And as the fleet continues to grow in the Gulf, we'll need to add for that fleet. We certainly expect to protect our market share position, and of course, the types of margins and return that we generate in that business are going to be very attractive to us from a capital investment standpoint.

Operator

Our next question is from the line of Stephen Gengaro with Sterne Agee.

Stephen D. Gengaro - Sterne Agee & Leach Inc., Research Division

Two things I would like you to address, if possible. The first, the contracts on the '11 pressure pumping fleet, have you had -- or would you have any discussions with customers about changing the terms for, obviously, in exchange for other work either any ancillary services and/or additional contract term?

David D. Dunlap

Well, I'm not going to say that we wouldn't. I mean, I think that when a customer comes to talk to you, you always want to put yourself in a position of listening. But at this point, those contracts are held with customers. They continue to have a pretty robust level of activity, and we have certainly accommodated those customers in the past and completely accommodated those customers in the past as well when they had a desire to move the application of one contract from one basin to another. And so I don't want to make it sound like we've signed those contracts and dig our heels in the sand and don't speak to customers about them again because that's not the case. But to say that we're renegotiating those contracts would be inaccurate.

Stephen D. Gengaro - Sterne Agee & Leach Inc., Research Division

Okay. And then on the margin front, you talked a little bit about margin progression as we go through the year. If we look at, I guess, particularly on the Subsea and Well Enhancement side, your comments on flattish margins from here, is that a combination of improvement internationally on the Gulf and deterioration in the U.S.? And if so, can you give us any color on the magnitude as far as how you're modeling things?

David D. Dunlap

Yes. Overall margins internationally, I think, as we look through the second half of the year, are not significantly different than what we experienced in the first half of the year. As time goes on, that international revenue base does build up, but it's happening at a margin that I think is fairly consistent with what we've experienced. Did that answer your question?

Stephen D. Gengaro - Sterne Agee & Leach Inc., Research Division

And then the Gulf relative to North America land, U.S. land, is there any give-and-take period? Any color on the U.S. land side particularly, I guess, is what I'm getting at.

David D. Dunlap

Yes. I mean, the color on the U.S. land side would be -- our expectation that utilization in the second half of the year and in some cases, pricing in the second half of the year, is going to be less than what it is coming out of Q2. And so most of what we're projecting as far as changes going forward, change is primarily driven by our expectations on U.S. land.

Stephen D. Gengaro - Sterne Agee & Leach Inc., Research Division

Okay, great. And then if I could slip one final one in, in your mind, the biggest variable between the top and bottom of your guidance?

David D. Dunlap

Yes. It's -- I mean, it's clearly North America. I mean, the whole reason that we're adjusting guidance was based on this change in expectation we had for the near term for North America, and I'd say it completely revolves around that.

Operator

Our next question is from the line of John Daniel with Simmons and Company.

John M. Daniel - Simmons & Company International, Research Division

Dave, you made a comment in your prepared remarks about awards in Brazil. Can you elaborate on those awards and if they had any impact on Q2 results?

David D. Dunlap

They did not have any impact on Q2 results. We've had a couple of contract awards, one that we're gearing up for kind of in the second half of the year that is relative to miscellaneous pumping. We still have several that are in the Q. So to answer your question, they did not have an impact on Q2.

John M. Daniel - Simmons & Company International, Research Division

Okay. Next one for me was just in response to an earlier question. You mentioned that Q3 revs would be down. Can you just characterize that for us, whether that's low-single-digit declines or high-single digits?

David D. Dunlap

From a revenue standpoint, I mean, we think of it as being kind of the single digits. I'd characterize it as kind of between 5% and 10%.

John M. Daniel - Simmons & Company International, Research Division

Fair enough. And then just a housekeeping for me, and if you said this earlier, I apologize. But can you remind us what the average horsepower was in Q1? Also, what it was in Q2? And then, where you stand today and what remains on order? And that's it.

David D. Dunlap

I don't have that average horsepower sitting in front of me, John. If you'll get with us after the call, we'll pass it on.

Operator

[Operator Instructions] Our next question is from the line of Mike Schrebcast [ph] with Olive [ph] Capital.

Unknown Analyst

Sorry, I must have missed what you guys said you expect for CapEx for the rest of the year and I just have a follow-up after that.

David D. Dunlap

Yes, we think overall capital spending -- we've not changed our guidance on that at this point. We think overall CapEx spending, what we've guided to in prior calls, would be something in the range of $1 billion to $1.1 billion. The only comment that I did make is that, that is a pace of capital spending that is slowing down as the year progresses, and I wouldn't be surprised if it came in something less than $1 billion in total for the year.

Unknown Analyst

And can you talk a little bit about how -- now that there's some excess equipment out there, how does that impact your need to spend versus moving equipment? And how are you -- what are you seeing in the industry? Are there less people building or buying equipment versus just moving equipment?

David D. Dunlap

Yes. I mean, I think, overall, industry-wide capital spend orders in the second half of the year are down significantly. And so there's still some equipment that is coming into the market, although we certainly hear about a lot of our competitors that are taking delivery and parking that equipment, and we'll do some of the same. I've mentioned that we would do that in the -- for instance, with fracturing assets if we don't see immediate opportunities. And so a general impression is that as we exit 2012, there's not a lot of equipment that'll be coming into the market. It's fairly rare now that you hear about people speaking of orders for new equipment in 2013. And so it kind of implies that we're entering a period here where there won't be a lot of new capacity coming in. I expect that there will still be some movement that people have of assets from the dry gas basins to the oily basins. But my expectation is that the bulk of that asset migration has already taken place.

Unknown Analyst

And I think generally, players in your industry have said we have to spend a certain dollar of CapEx and that should flow through to revenue within, let's call it, 1 year to 1.5 years. Do you think that dynamic is changing where the productivity of your existing asset base is going to go up just because you're moving equipment from one basin to another, and instead of going out and buying equipment to fulfill an order, you're just utilizing existing equipment?

David D. Dunlap

Well, I think -- maybe I don't understand your question perfectly well.

Unknown Analyst

I guess my question is, why is it -- what are you going to be spending CapEx on if the top line -- or if the opportunity set out there comes down a little bit and it sounds like you have the ability to move equipment, why do you need to spend as much CapEx?

David D. Dunlap

Yes. So the bulk of our CapEx in 2013 from a growth standpoint, in fact, all of our CapEx from a growth standpoint will be focused to the international markets and to the Gulf of Mexico. We will be entering an environment of what we generally describe as maintenance capital spending for the U.S., and we think that, that maintenance capital level is on the order of, call it, $100 million a year. So obviously, substantially lower than what we invested in 2012.

Unknown Analyst

And any -- from your perspective in talking with customers, natural gas has moved up over $3. Have you seen a change at all between natural gas moving from the low $2 to $3 in some markets where natural gas drilling could start to pick up?

David D. Dunlap

No. We've not seen any movement from a drilling activity standpoint as the result of the recent improvements in natural gas prices. Clearly, it's helpful from a cash flow standpoint for those customers that either aren't fully hedged or are only -- that are partially hedged. But we've not seen, or I would not anticipate, any movement in a natural gas drilling market until we get to a 12-month strip that's closer to or in excess of $4. And I think that's -- I feel pretty strongly about that actually in speaking to customers. And of course, those that are more in the unconventional shale resource basins, when they start to get more active, they're not going to activate a single rig or 2 rigs in all likelihood to take advantage of efficiencies and what they know about that horizontal well fracturing market. They'll be adding capacity in increments of 4 and 5 and 6 at a time. So that -- in order to...

Unknown Analyst

And that would be favorable to pricing for you guys if that happens?

David D. Dunlap

Yes. So really don't see that moving until we get up to about $4.

Operator

Our next question is a follow-up from the line of Matt Conlan with Wells Fargo.

Matthew D. Conlan - Wells Fargo Securities, LLC, Research Division

Just a quick follow-up here, some clarification. You're talking about the revenue trajectory you're expecting from the second quarter to the third quarter. I think you mentioned down 5% to 10%. Was that just the U.S. land revenues or total revenues?

David D. Dunlap

That's just U.S. land revenue. It's really U.S. land services revenue, to be more specific.

Operator

And there are no further questions at this time. I would now like to turn the call back over to management for closing remarks.

David D. Dunlap

I thank all of you for joining us, and we'll talk to you next quarter.

Operator

Ladies and gentlemen, this concludes Superior Energy Services' Second Quarter Earnings Conference Call. If you'd like to listen to a replay of today's conference, please dial 1 (303) 590-3030 with the access code of 4549044. ACT would like to thank you for your participation. You may now disconnect.

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