Superior Energy Services Management Discusses Q1 2013 Results - Earnings Call Transcript

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Superior Energy Services (NYSE:SPN) Q1 2013 Earnings Call April 26, 2013 11:00 AM ET

Executives

Greg A. Rosenstein - Executive Vice President of Corporate Development

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

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

Analysts

J. Marshall Adkins - Raymond James & Associates, Inc., Research Division

James Knowlton Wicklund - Crédit Suisse AG, Research Division

Robin E. Shoemaker - Citigroup Inc, Research Division

Jeffrey Spittel - Global Hunter Securities, LLC, Research Division

Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Kurt Hallead - RBC Capital Markets, LLC, Research Division

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

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

Trey Cowan - Clarkson Capital Markets, Research Division

Michael R. Marino - Stephens Inc., Research Division

Operator

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Superior Energy's First Quarter Earnings Conference Call. [Operator Instructions] This conference is being recorded today, Friday, April 26, 2013, and I would now like to turn the conference over to Greg Rosenstein, Executive Vice President. Please go ahead, sir.

Greg A. Rosenstein

All right, good morning, and thank you for joining today's conference call. Joining me today are Superior's President and CEO, David Dunlap; and CFO Robert Taylor.

Let me remind everyone that during this conference call, management may make forward-looking statements regarding future expectations about the company's business, management's 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. And in accordance with Regulation G, the company provides a reconciliation of these measures on its website.

I'll now turn the call over to David Dunlap.

David D. Dunlap

Okay. Thank you, Greg, and good morning to everyone. Thanks for joining us. Last night, or yesterday afternoon at the close of market, we reported quarterly revenue of $1.1 billion, EBITDA of $278 million and net income of just under $64 million, or $0.40 per diluted share.

The first quarter unfolded as expected, with increasing U.S. land activity in March and seasonality in the Gulf of Mexico and Asia-Pacific markets.

Despite a 3% decline in the Baker Hughes rig count, our U.S. land revenue was flat from the fourth quarter levels as completions activities started to increase during the month of March.

Our pressure pumping and well service rig revenue and profits increased from the fourth quarter. In fact, it was the second consecutive quarter that our pressure pumping revenue and profits rose due to higher utilization of our contracted horsepower. Coiled tubing revenue on U.S. land was essentially unchanged from the fourth quarter. Gulf of Mexico revenue decreased 2% from the fourth quarter levels. The first quarter is typically burdened by seasonality, especially for shallow water optional work. As a result, a 2% decline is a better outcome than one would think, and it speaks of the resilience of the Gulf of Mexico market. Drilling Products and Services revenue from the Gulf grew almost 2% as the deepwater market remained strong. We did experience slightly lower margins, and anticipated as a result of low margins on some Gulf of Mexico decommissioning projects.

To put the Gulf of Mexico recovery in perspective, our first quarter revenue was 36% higher than it was during the first quarter of 2012. International revenue decreased 17% from the fourth quarter due mainly to seasonal declines in our subsea construction business in the Asia-Pacific market, and well control work that did not repeat during the quarter. The international revenue decline shows up in the Subsea and Technical Solutions segment. We actually experienced growth in our Drilling Products and Services international revenue by 4%, and our Production Services international revenue by 7%.

We had a strong message to the field during the first quarter to keep costs and capital spending in check, in light of the U.S. land market uncertainty. And as usual, the field performed very well for us. The result is that we're still very much in line to be a strong free cash generator during 2013. After Robert walks you through some of the financial details of the quarter, I will discuss our guidance and outlook. And with that, I now 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 fourth quarter 2012. In the Drilling Products and Services segment, revenue was $194 million, and income from operations was $57 million, which represents a 1% sequential increase in revenue and 1% sequential decline in operating income.

The reduction in operating margin is primarily a function of business mix, with accommodations growing at a faster rate than the downhole drilling tools. International revenue experienced the highest segment growth rate at 4% to $50 million due to increased rentals of accommodations in Europe. We also experienced increases in specialty rentals in Latin America. The Gulf of Mexico revenue increased 2% to $70 million, which was offset by a 2% decline in U.S. land revenue to $74 million. In the Onshore Completion and Workover Services segment, revenue was $426 million, and income from operations was $50 million, which represents a 2% sequential increase in revenue, and a 6% sequential increase in income from operations. All of the revenue comes from the U.S. land market.

Our pressure pumping revenue increased 8% due to an increase in volumes pumped in the Eagle Ford and Permian Basin. Well services revenue increased 7% due to improved utilization. In the Fluid Management business, revenue declined 7%, primarily due to lower transportation and storage utilization due to weather in Colorado and Oklahoma, as well as a shift to piping water bursts is hauling in the DJ basin [ph].

Production services revenue decreased 1% to $367 million, and operating income decreased 11% to $28 million. U.S. land revenue declined 3% to $215 million, primarily due to the declines in snubbing and remedial pumping. The biggest story is that coiled tubing was essentially flat, as moderate revenue declines from the northeast in the Anadarko basins were offset by activity increases in the Bakken and Eagle Ford. The Gulf of Mexico revenue declined 5% to $54 million, primarily due to seasonal factors which lead to a decline in coiled tubing and wireline activity. International revenue increased 7% to $97 million, primarily due to increased production testing activity in Argentina, remedial pumping in Brazil and cementing activities from our recent acquisition in Columbia. In the Subsea and Technical Solutions segment, revenue was $148 million, which represents a 25% decline from the fourth quarter. This segment's loss from operations was $6 million, compared to $10 million income from operations in the fourth quarter. This is a segment that is impacted most by seasonality, both in the Gulf of Mexico and in Asia Pacific. The Gulf of Mexico revenues declined 4% to $84 million, primarily due to lower well control work, partially offset by an increase in completion tools and products.

International revenue was down 50% to $48 million due to lower-subsidy construction work and well control projects in the fourth quarter that did not repeat. U.S. land revenue increased 8% to $16 million. The costs from this segment are relatively fixed, so the decremental margins are high. In addition, as Dave mentioned, we had lower margins on 2 decommissioning projects in the Gulf of Mexico. Those margins will not repeat moving forward.

Turning to the balance sheet. As of the end of the first quarter, our net debt was $1.8 billion. The debt to EBITDA as of the end of the quarter was 1.5x, and debt to total capital was 30%, both of which are essentially unchanged from year end. Capital additions during the quarter were about $130 million. Our G&A in the first quarter was lower than our fourth quarter run rate, due to several items, including: Compensation-related expenses; insurance and risk management expenses; our net foreign currency gain; and bad debt expenses. As our business improves, we do anticipate and these additional expenses on some of these areas that I just mentioned. As a result, we think you should model G&A in a range of $157 million to $160 million for the second quarter. With respect to DD&A, we think you should model a range to $152 million to $155 million. Interest expense should be in the range of about $27 million to $29 million, and weighted average share count should be approximately $160 million. I will now turn the call back over to Dave, who will discuss our earnings guidance and outlook.

David D. Dunlap

Thank you, Robert. As we mentioned in the earnings release, there is no change to our earnings guidance range for 2013 of $1.85 to $2.35 per share. Our first quarter was in line with the midpoint of our expectations. The advance of the U.S. land market continues to be the biggest variable in our 2013 expectations. Improvements in the completions market did not really become evident until the second half of March, but the fact that we witnessed those improvements during the first quarter does give us confidence that we are off bottom, and we'll see an improvement in the second quarter. The pace and slope of the activity increase is still not perfectly apparent, and remains the reason for the wide range of our guidance. We did see some increases in rig count towards the end of the first quarter, and that continues into April. I expect that rig count will continue to improve during the course of Q2 and through the remainder of 2013. Those increases will be directed to both oil and gas-related activities, although we believe that the only gas shale basin that we'll see any significant increase will be in the Marcellus. Oil-directed activity would probably be increasing at a more rapid pace, but in certain areas, particularly the Permian Basin, activity is constrained as infrastructure buildout continues, and operators seem to be waiting for infrastructure before scaling up completions in drilling activity. To reiterate what we said on our last call, the midpoint of our guidance does not anticipate any pricing improvement. So margins are not forecasted to approach where they were in Q1 and Q2 of 2012, but should improve from the first quarter of 2013 as utilization improves. We continue to be encouraged by our results in the international market. Although our headline number of international revenue is down from Q4, the reductions were in well control and subsea construction. The focus of our international development continues to be in Drilling Products and Services and in Production Services and both of these segments realize gains on a sequential basis. Latin America and Asia are really leading the way for us. In Colombia, we closed on an acquisition that gives us very nice capabilities in pressure pumping, which I expect we will soon expand to include Intervention Services. Our Rental business in Brazil continues to expand, and we've now received official notice from Petrobras of a land stimulation contract that we will be delivering equipment for in the second half of 2013. I will remind you that the bulk of our growth CapEx in 2013 is devoted to the international business and growth is proceeding as planned. The Gulf of Mexico market is also advancing as planned. Although we always see a seasonal slowdown in Q1, the rest of the year is shaping up nicely for us. I don't think that there is a diversified company out there that is in a better position to capitalize on Gulf of Mexico growth with our very mature market -- very mature service network on the Gulf coast and well-established rental tool brands. Our market share position in all of the product lines of -- that we offer in the Gulf Mexico continues to be very strong. The bottom line here is that we are executing as planned. Our people in the field and our management team continue to do a great job in building this company in the right way, with a focus on safe and efficient operating performance. And that concludes our prepared comments. We'll open the line up for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from the line of Marshall Adkins with Raymond James.

J. Marshall Adkins - Raymond James & Associates, Inc., Research Division

Dave, it seems like you guys kicked butt -- at least in our model, kicked butt on the completion work over side and also drilling product side. The real shortfall for us was the subsea. How much of that subsea was seasonality versus kind of onetime stuff? What I'm trying to really get to is, should we expect that business to improve meaningfully the second half of the year?

David D. Dunlap

Yes, Marshall, you can actually expect it to improve in the second quarter. Most of what we saw in the decline in that business from Q4 was seasonality, and it's primarily in Hallin Marine in the subsea construction business in Asia, which since -- Superior acquired that business in 2010. Q1 is always the low point. And I -- their business has improved consistently year in, year out in the second quarter, and I expect it to do the same this year. The other component that was off from Q4 is well control. And this is primarily in the area of the emergency response work that we do in well control, and that's always a difficult part of our business to predict. They had a good, strong fourth quarter and not a lot of work in the first quarter. So I can't say that, that's going to recover to fourth quarter levels in Q2, but it should probably be better in most quarters than it was in Q4.

J. Marshall Adkins - Raymond James & Associates, Inc., Research Division

Got you. Second question. Drilling Products and rental tools margins were just awesome. Can you keep -- can you sustain those?

David D. Dunlap

I don't see why not. I mean, where those margins and return levels are in that product line are consistently what industry has seen in that product line over a long period of time. I have been looking at rental companies for 20 years, and as you well know, I coveted those in my prior life and real happy to have one now. Because historically, performance in that space has been extremely good. And where we are today, I think is, kind of midmarket point.

J. Marshall Adkins - Raymond James & Associates, Inc., Research Division

Yes, so I guess I translate that to me, you're -- that's where a lot of your CapEx will continue to go?

David D. Dunlap

It always is. I mean, it's -- we're very competitive from a capital expansion standpoint in this company. And certainly, the downhole rental guys always get their share of it because their margins and returns are so predictable.

Operator

Our next question comes from the line of Jim Wicklund with Crédit Suisse.

James Knowlton Wicklund - Crédit Suisse AG, Research Division

Your guidance range, wide enough to drive a truck through, that's good. Can you talk about what would make you hit the bottom into the range, and what would make you hit the top end of the range? And I understand the easy question is, depending on activity. But is there anything you can do to influence, or what can you do to influence the upper or lower ends of those range?

David D. Dunlap

Well, I mean, clearly from an execution standpoint, the cleaner our execution is in the field, the more it favors getting into the higher end of that range. But I would certainly say that the primary reason for the wide range that we have is uncertainty of U.S. land market. And I don't mean to say uncertainty and cause you to believe that I have a negative spin on that, because I don't. We do believe that we'll continue to see activity gains as the year progresses in the U.S. land market, but the pace of that activity gain is, it's difficult to predict. And us -- and I can use Q1 as a perfect guidepost for this. We saw very low activity in January. We saw very little activity in February. And I got to tell you, the first couple of weeks of March did not look real good either. Most of the gains we saw in utilization and activity were realized in the second 2 weeks -- or the last 2 weeks of March. And so, that gives me good confidence going to the second quarter, that we picked up off a bottom and should have a nice quarter in Q2 relative to Q1. But how fast that activity increase continues to advance during the second quarter really sets the stage for the rest of the year. Because if you think about advance, it means that we've got a certain pace of activity on the first day of the quarter, and expect to have a bit higher pace of activity at the end of the quarter. And that sets the stage for Q3. So I know I'm rambling a little bit here, but it really is the explanation for the wide range. And there are still unknowns about how activity advances, even during the second quarter.

James Knowlton Wicklund - Crédit Suisse AG, Research Division

At least we're seeing a pick up. That's a start. My follow-up question, if I could. I assume that you guys are seeing some divergence to, as opposed to revenue generation in rig count? Vis-a-vis the constant comment of rig efficiency, fewer rigs to fill the same amount of footage in your wells? Have you guys seen that separation yet?

David D. Dunlap

Yes, I don't know that, that the separation is usually apparent. But it is clear that efficiency gains and -- are driving utilization. And for us it's -- our utilization gets measured in a variety of ways. You guys have heard me talk about on the frac side, 7 days versus 5 days utilization. But even on those crews that are working 7 days, we're seeing improved utilization as the crews execute better and those operators become more efficient.

Operator

Our next question comes from the line of Robin Shoemaker with Citigroup.

Robin E. Shoemaker - Citigroup Inc, Research Division

Wanted to ask you about the pick up in completions in late March. Do you think there was kind of an -- that the E&P companies are working off an inventory of uncompleted wells? And so does that late March pick up continue in April? And -- because the drilling rig count's been kind of flat, but it seems like everybody in the industry experienced more activity, at least in terms of completions in the first quarter, but without a pick up in the rig count?

David D. Dunlap

Robin, I don't necessarily think of this in terms of a backlog. I think of it more in terms of an urgency to get wells completed a bit sooner. And we saw this lack of urgency in the second half of 2012, in many cases, it was -- that lack of urgency was demonstrated in the form of going from a 7-day completion operation to a 5-day completion operation. What we saw in late March was a greater sense of urgency. And that does mean that people get wells completed closer to when they were finished drilling than they probably were in the second half of 2012. So I don't know if I answered your question perfectly. It's more urgency to get wells completed, certainly, that we begin to in see late March, and I do think that continues through the second quarter. And I think some of that lack of urgency early this year was operators deliberately going slower, in order to give infrastructure, particularly midstream infrastructure, a chance to catch up.

Robin E. Shoemaker - Citigroup Inc, Research Division

Yes, right. So I want to turn to the coiled tubing business for a minute. And just, if you could describe what the pricing competition is there? Utilization of your coiled tubing units and have -- are we close to the, or at, or past the bottom of the severe pricing competition in coiled tubing?

David D. Dunlap

Well, I think that we are. I mean, certainly there are differences from one basin to the next. But overall, what we saw in the coil business in Q1 was utilization in pricing that was relatively flat with where we were in Q4, and you may see a little bit of price competition in one basin, you may see a little bit of opportunity improve price in another basin, but at the end of the day, in our large, very diversified coiled tubing business, what we saw was kind of flat performance. And I think as we go forward, we've been very clear in stating that we don't expect coiled tubing prices overall to improve during the course of the year, but as completions activity gets a bit busier, we would expect some utilization gains that drive some margin improvement. And our belief is that we'll see a bit of that in the second quarter, and a little bit more as we get into Q3 and Q4.

Robin E. Shoemaker - Citigroup Inc, Research Division

And is the industry -- I mean, how much idle capacity, industry-wide, do you think we're at now, in terms of coiled tubing units?

David D. Dunlap

Well, I think that what has happened is the slowdown in completions has caused the smaller coiled tubing units and the older 1.5 inch units to become much less utilized. The units that are being used on completions today are almost all 2-inch units. And so, if you thought about utilization for the smaller units, I'd say that there are probably a number of those, that companies have that are stacked. Most of our fleet is 2-inch units, but I know even the few smaller units that we have are not very high utilization. As a matter of fact, we've looked at the possibility of transferring some of those smaller units into international markets that have demand for them right away.

Operator

Our next question comes from the line of Jeff Spittel of Global Hunter Securities.

Jeffrey Spittel - Global Hunter Securities, LLC, Research Division

Maybe if we can touch on the wireline. I think I saw on the prepared comments and some relatively constructive commentary about how that held up, which is a little bit in contrast to some of your peers. Can you give us a little better sense of what the market dynamics are there?

David D. Dunlap

Well, I mean it's -- I would not want to characterize it as a great market. I mean the cased hole wireline business is -- has been relatively flat for some time. And so much of what's done in that business today is really shaped charge resale. But I think we were -- I don't want to make a big deal out of it really, Jeff, I mean, you were always encouraged to see a good result on that business. But I don't believe it's something that we're expecting huge increases going forward with. As we have some completions activity, it'll generate more shaped charge resale.

Jeffrey Spittel - Global Hunter Securities, LLC, Research Division

Sure. And then I guess, are you starting to see some evidence of a little bit better demand for kind of gas maintenance and work-over type activities? Whether it's in the unconventional or conventional plays? And do you think that's more of a seasonal element? Or do you think maybe it's a little bit more sustainable as the year progresses?

David D. Dunlap

Yes, I don't know. I mean it's -- the Service Rig business did well in the first quarter. I don't know that, that was a lot driven by gas maintenance work. I think it was probably more driven by a little bit more completions work and a little bit better mix. So that business, for us shifted during the course of 2012, and about 60% of our kind of Q1 '12 revenue would've been on completions work and 40% on production. In Q4, it dropped all the way to 40% on completion and 60% of production, and I think a little bit better mix probably helped us more than anything in Q1.

Operator

Our next question comes from the line of Byron Pope with Tudor, Pickering, Holt.

Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Dave, when you mentioned the improvement in pressure pumping utilization, I was expecting to hear you talk about the Marcellus, as opposed to the Eagle Ford and the Permian. So it sounds like, with regard to gassy basins the Marcellus is the one originally where you -- it feels like customers could increase activity. Just was wondering, if you could provide a little more color on -- your thoughts on your exposure in the Marcellus is, and what you see there with the next over the next few months?

David D. Dunlap

We've got one active frac fleet in the Marcellus today. We do have some stacked equipment that's up there, which I'd love to take off the fence some time in 2013, but I don't know that, that's included in our guidance at the moment. We -- that one fleet has been utilized. It's a contract fleet. It's really a fleet that delivered about flat activity for us from Q4 to Q1. And so I can't say that we've been any real big beneficiary as a result of any activity changes in the Marcellus to this point. But certainly, we have -- over the last 12 months, added some capacity in fracturing out in the Permian Basin, and seeing some real nice growth in that business. And in the Eagle Ford, we have 4 fleets in the Eagle Ford. They're all contracted fleets, and they are probably 4 of the most efficient fleets that we have anywhere in the company.

Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. And then, second question for me. Just relates to CapEx. You mentioned that you guys underspent a little bit in the first quarter, relative to what you originally thought internally. And I'm just wondering, is that bias that the full-year CapEx number down? Or is it just waiting to see how activity comes through in the next few months before committing that?

David D. Dunlap

You characterized it very well with the last part of the comment there, waiting around to see how the activity shapes up during the course of the year. I don't think we have any changes in our overall thoughts of CapEx for the year, which we've guided you guys to $600 million to $700 million. And really, what we were trying to do in the first quarter and the message that sent to the field is, I say, listen guys, we're starting out the year slow, we know we're starting out the year slow. Let's make sure that we keep our -- a conscious effort to keep costs contained and to keep capital spending contained, and make sure that the year is going to progress the way we think it will from an activity standpoint. Today I feel pretty confident about that, but the first week of January, there's still a lot of unknowns out there, right?

Operator

Our next question comes from the line of Kurt Hallead with RBC Capital Markets.

Kurt Hallead - RBC Capital Markets, LLC, Research Division

You're doing something right, your stock's up 5.5%. Well done.

David D. Dunlap

Thank you.

Kurt Hallead - RBC Capital Markets, LLC, Research Division

So a question I had for you was, in the past, Dave, you gave some indications as a potential use of cash and returning cash to shareholders in some form or another. Can you give us a quick update on your thoughts there?

David D. Dunlap

The thoughts are exactly the same as they've been, really, for the last 9 months, as we've been talking about: use of cash. And we continue to be in effort to pay down some debt, an exercise that really takes us through the first half of this year, and at some point in the second half of the year, we'll have that $300 million of debt brought in, and the revolver back down to 0. And assuming the year progresses the way we think it will, we think we start to build free cash in the second half of the year, and we'll be talking to the board about how to get that back to shareholders. There's not really another good opportunity for us to buy in debt for couple of years, and there's also not a real reason for company like ours to build cash. I think long-term, having a structure whereby we are regularly giving cash back to shareholders is the best option for us. But it's still one that really doesn't become available to us until later this year.

Kurt Hallead - RBC Capital Markets, LLC, Research Division

Now, and again that context, I was under the impression that it was $150 million of debt reduction, and you just mentioned it's $300 million, so?

David D. Dunlap

Yes, sorry. You're -- I mean, it started out as $300 million in total. We brought in $150 million of that in the second half of 2012. So we've still got $150 million left to go.

Kurt Hallead - RBC Capital Markets, LLC, Research Division

Okay. And then, you think then the actual return of cash to shareholders is truly a '13 event? Or is it more likely to be a '14 event?

David D. Dunlap

I think a lot's going to depend on what happens and what we see out there in the second half of 2013. I would sure like for this to be something that we're able to initiate during this fiscal year. It may carry out to 2014. But as I said, I don't -- there's not a real reason for us to be a company that builds cash on the balance sheet. And I think once we've got the revolver at 0, and this overall, $300 million and notes brought in, that's a point in time when where, assuming our long-range forecast all feels real good that we'll start looking at options for getting cash back to shareholders.

Kurt Hallead - RBC Capital Markets, LLC, Research Division

You've taken a very measured approach to your international expansion opportunities. What do you have on the docket for 2013? And what are some areas you may be looking at in 2014?

David D. Dunlap

Yes, so I mean, we are anticipating now about 30% overall growth in our international revenue in 2013 from 2012. It's happening primarily in the same countries which I have talked about consistently for the last couple of years, mainly in Latin America and Asia, but also in Saudi Arabia. We always have a few places that -- where we're doing, I'll call it kind of reconnaissance work, and thinking about setting up operations, and some of that may be realized later this year, and some maybe in 2014, but they're still kind of focused in those same regions, Latin America and Asia.

Operator

Our next question comes from the line of John Daniel with Simmons & Company.

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

Dave, you guys mentioned a lot of the growth came the last couple of weeks of March. And some of our colleagues had to write the numbers down right, had high single-digit revenue growth quarter-for-quarter, and things, such as pressure pumping and well service. Are the gains and activities the last several weeks so significant that you would see similar top line growth for those product lines in Q2?

David D. Dunlap

Well, I mean, I think the top line -- we think that, that top line growth carries over from the last couple of weeks of March. And what it does, I mean, it kind of, it kind of resets an activity level for us. We were low at the beginning of the quarter and we got better at the end of the quarter. We just considered that -- say that activity level held, I mean, that does represent a pretty nice overall increase from Q1 to Q2. It could also be a little bit better. But that's that unknown that's out there, John, and how the market advances during the course of Q2, where it really becomes the primary determining factor in where we ultimately wind up finishing and relative to our range of guidance. But I feel pretty good about the start to the second quarter now, based on seeing that activity increase in March. And I can't over emphasize for you guys how difficult this budget is for 2013. And our mood and attitude on this, certainly with you all has remained consistent, we did not believe that the market would get busier until the very end of the first quarter, and we were right.

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

Okay. One more on the well service rig business. Is the growth that you expect there, is that a function of working more hours on your existing fleet, redeploying, maybe idle rigs? Or do you guys see opportunities to build in that new workover rates this year?

David D. Dunlap

So we've got a few new service rigs that come -- are coming into the fleet this year. Most of our focus recently has been on some of the new generation, automated-type of rigs, and we've got, I think, 3 of those that are in the field now, and there's a few more that are budgeted to come in during the course of the year. So I mean, what's happened in the business is, we're seeing a little bit more completions work, as opposed to production work and that's higher-quality revenue. And as I said, a little bit more capacity that's coming into the fleet.

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

Okay. The final one for me, David, is just on Colombia. I think that you mentioned that -- a small acquisition there. Can you just talk a little bit more about when that closed? Size of the deal, and so forth, just a bit more? And what maybe, what you already had in country before that?

David D. Dunlap

Yes, sure. So we -- the company started out in Colombia about 3 years ago, I guess, with a very small inspection business, a pipe inspection business that we bought in Colombia, and after that, we added some rental tool fleet to our business there. We've been looking for a way to bring some of our intervention or production services into the market, and in doing that, we were eyeballing a number of local companies and this particular company that we acquired is one that we began conversations with late last year. It's a small pumping services company, a relatively new player in the market. I think they've been in business for 4 or 5 years, which is good because it means their equipment is new. They've got nice base of business today that's spread out between a few of our customers, but it's a good service operation for us to build on. And we closed that acquisition on March 1, so not a lot of their result is really embedded in our numbers, but so far, what we've seen performance-wise is well within the expectations of what we believe the business could produce. And John, really, this is the type of international acquisition that we have -- we have focused on. It's relatively small. In terms of revenue, it's kind of a $25 million-a-year operation. Very similar in size and scope to what we did in Argentina last year. And I'd love to go do several more of those during the course of the year, and years to come, because they're just perfectly complementary with our international expansion strategy.

Operator

[Operator Instructions] Our next question comes from the line of Daniel Burke with Johnson Rice.

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

Dave, I thought I heard you allude to 30% year-over-year growth in international. Wanted to confirm that, that was correct. I guess I was curious, more broadly, did the -- as a way of assessing your view of the first quarter, did the decline in subsea technical solutions revenue internationally, was the magnitude of that decline a surprise to you? Or about in line with where you thought that figure would end up?

David D. Dunlap

About in line with where we thought it would be. I mean, you -- we constantly talk about seasonality in Q1, and although the impact of that seasonality on -- in terms of our entire result as a company is certainly not as loud as it was before our Complete acquisition. It's still a factor that's out there, and where that business landed in Q1 was in line with what our expectations were. And so, of course what that means is, we expect it to get better in Q2, which is also a part of what we've seen historically in this mix. You guys are just getting better visibility on this than you've ever had before. This was a business that was buried in subsea and well enhancement in the past. But now that we've got it segmented for you, you can see it a lot more clearly.

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

Yes, I appreciate that. And then we can go back in history and see the last couple of years, which is helpful to see that as well, and get some instruction into the margin and revenue bounce you typically get it to Q2. And actually, to that end, is there a way to address? It's good to hear that the decommissioning-related margin pressure you saw in Q1 won't continue into Q2, but is there a way to describe what level of impact that had on Q1?

David D. Dunlap

All right. It was -- it's not a needle mover for us, how's that? I mean, that's a -- that's about $100 million a year business for us, in total. D, I'm speaking of the decommissioning market in the Gulf of Mexico. And so, when they have a little bit of cost overrun, which often in Q1 is a result of weather delays, it's not a needle mover for us.

Operator

Our next question comes from the line of Trey Cowan with Clarkson Capital Markets.

Trey Cowan - Clarkson Capital Markets, Research Division

Looking at just the complexion of things, you spoke to more production-related activities going on right now, and that would kind of suggest that over the long run, I mean, you have 3 to 5 years out. We are actually seeing more artificial lift because there's more liquids in oil drilling being done right now. How do you guys see that impacting your work over services?

David D. Dunlap

This is a great question and, Trey, and it really -- it really -- the heart of the question is, is what as an industry, are we going to do to maintain production in horizontal wellbores. And there has not been a lot of recompletion work done in horizontal wellbores to date. There are different opinions in industries to how this will be done. I have a hard time believing that we were going to spend a lot of time and effort and money as an industry, in trying to improve or enhance production in an existing horizontal well that has largely depleted or seen production decline. And one of the thoughts people have had is well, you get this big horizontal wellbore, you got $6.5 million or $7 million invested in, why don't we go refrac it? And I think there's a tremendous question out there as to whether or not the results of refracing would be a good investment. I mean, you've already drained part of that cylinder that surrounds that horizontal wellbore with your initial completion, and I'm not sure that, in these very tight formations, we're going to be able to improve that recovery by recompleting that same wellbore. Now if you wanted to go into the vertical and shoot the horizontal off into another direction, that's a different story, but the way operators are laying out horizontal wells in these fields, I'm not sure even that opportunity exists. I don't if I answered your question there. I mean, artificial lift is an easy one, because we see operators reconfiguring their completions in these wells as they experience pressure depletion, and artificial lift is part and parcel to what they do there. But it's a little bit harder to see the visibility on how recompletion activity would occur on these horizontal wells.

Trey Cowan - Clarkson Capital Markets, Research Division

Got you. And then on a totally different subject, you mentioned early in your comments that the DJ Basin [ph] was piping more water than it had in the past. Can you just give us some insight into what's going on there, as far as to shift in sentiment, what's making this behavior shift?

David D. Dunlap

Well, I mean it -- let me preface this by saying, there is different behavior in different basins, related to transport of water, and one of the things we've seen, some of the DJ operators do is, is pipe more or run more water in ditches, really, which certainly eliminates the need for some of the transport requirements that have historically existed in the DJ. But you go to the Permian or you go to the Eagle Ford, you go to another basin, and that's not the case at all. In several of those places we see increasing demand for trucks. So I think when operators have the opportunity to invest in water-moving infrastructure that's going to be there for a long time, that they can build out in an efficient way, we'll see operators do that. You've seen that in the Missisippian Lime, where so many of those operators have invested in hard -- buried pipes in the ground, move water from a production standpoint, as well as from a completions standpoint. So it's not a common theme from basin to basin, nor from customer to customer. The DJ basin is one where there's kind of a concentration of customers. So when we see one of those customers that moves to a more permanent transport devices like pipes or ditches then it impacts us.

Trey Cowan - Clarkson Capital Markets, Research Division

Not to get too much into the weeds here, but is there any impact on the water cut that's coming out of the well? I mean, is there a greater water cut or a lesser water cut or is that -- that had some impact on it?

David D. Dunlap

Are you talking specifically to the DJ, or just in general?

Trey Cowan - Clarkson Capital Markets, Research Division

Well, I thought the Mississippian Lime had a greater water --

David D. Dunlap

Yes, so and the Mississippian Lime has a tremendous water cut. And I think, it's -- I think those wells come on line with about a 90% water cut. And there are other formations that operators are exploiting today that also come in at that high water cut. That's just a function of oil price. I mean, it gets very expensive to handle water, and you got to have an oil price that's high enough in order to support that additional cost. I think as long as you see an oil price deck that's kind of where we are today, there will continue to be these types of fields that are brought on line, because we can afford the water take away.

Operator

[Operator Instructions] Our next question comes from the line of Michael Marino with Stephens.

Michael R. Marino - Stephens Inc., Research Division

Can you remind us again on how much horsepower you have, kind of rolling into the spot market later this year? And the timing of that? And if -- is that something, if it does roll by, is it something we should kind of keep in mind in our models, given the difference in potential pricing?

David D. Dunlap

Okay. So I mean, we have -- around 4, I think it's 4 stacked frac fleets, and we did not really incorporate within our guidance and expectation that those fleets become unstacked during the course of the year. We've got some horsepower which comes off contract in the Barnett, during the course of 2013. I'll remind you that those are our smallest frac fleets. They represent less than 10% of our overall horsepower. And the expectation is that we'll find work for that horsepower. So that's probably in the callout market. I don't think in this market environment that there are great opportunities to kick off new contracts. So it's kind of a horsepower that we expect to shift from contract to spot, as the year progresses.

Michael R. Marino - Stephens Inc., Research Division

Okay, and it doesn't all happen at once? It's -- they're somewhat more staggered?

David D. Dunlap

That's right. It's staggered, and it happens during the course of the year. And another way to think about this, I mean, we're about 70% of our overall fracturing revenue, that is the result of contracts. And we kind of stay the same on that, as the year progresses.

Michael R. Marino - Stephens Inc., Research Division

Okay, that is helpful. How do you see the spot market right now, in terms of pricing? Is it down the bottom yet, is that your view?

David D. Dunlap

I don't know. It's very different from one basin to the next, and, we're not the perfect guys to speak to about pricing in the spot market, because we don't have -- we're not in every basin in the spot market. The Eagle Ford's a good example of that. I mean, we've got 4 of our biggest and most productive frac fleets that work in the Eagle Ford, but they're all contracted, so I'm not testing the prices there everyday. We do have spot capacity, it's in the Bakken. We have spot capacities in the Permian. We have been able to find work for that spot capacity that generates a margin for us that's consistent with a contracted fleet would deliver. So I'm talking all around your question, I know that. But it's mainly because we just don't have the visibility in the spot pricing in each of the markets on a day-to-day basis.

Michael R. Marino - Stephens Inc., Research Division

No, that's very helpful. So just kindly, if I could hone in a little bit on the guidance and how your flat -- frac fleets fits in there. If I'm understanding you correctly, you're not incorporating any idle fleets going to work, even at the high-end? But at the high-end, you might be incorporating higher utilization of existing contracts?

David D. Dunlap

That is exactly right. Now, whether it's existing contracts or higher utilization on the fleets, the revenue progression as it occurs during the year and actually, occurred during the month of March, as we saw higher utilization later in March than we did early in March, is driven by utilization -- that's not more equipment going into the field. And those utilization gains were nice for us. We still have several fleets that are on 5-day utilization. I think our total count was 6 on 7-day utilization at the end of March. I would expect that could improve some as the year progresses, but more than anything, this also goes back to the issue of efficiency. And in many cases, we see opportunities for efficiency enhancement, even on a 7-day fleet. And I'll give you an example of that. I mean, we had 4 of our frac fleets during the month of March. Four frac fleets during the month of March that averaged 2 million pounds of profit per day. That's pretty efficient. And, that in fact, that's -- I'd put that up against any company in the fracturing industry from an efficiency standpoint. And that's 4 fleets that did that. You pick up another fleet that has that kind of performance in the second quarter, and your utilization improved. And you didn't have any additional fleets necessarily that went on 7 days, but your overall utilization improved. And we expect to see some more of those opportunities as the year progresses.

Operator

There are no further questions at this time. I would like to turn the conference back to over to Mr. Dunlap for any closing remarks. Please go ahead.

David D. Dunlap

I think that we're finished with our remarks. I appreciate all of you joining us today. Thank you.

Operator

Ladies and gentlemen, this does conclude our conference for today. Thank you for your participation. You may now disconnect.

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