Oil States International, Inc. (OIS) Q2 2015 Earnings Report, Transcript and Summary

Welcome to the Oil States International Inc. second quarter 2015 earnings conference call. My name is Loren, and I will be your operator for today's call. [Operator Instructions] I would now turn the call over to Ms. Patricia Gil. Ms. Gil, you may begin.

Thanks, Lauren, and welcome to Oil States' second quarter 2015 earnings conference call. Our call today will be led by Cindy Taylor, Oil States' President and Chief Executive Officer; Lloyd Hajdik, Senior Vice President and Chief Financial Officer. And we are also joined by Chris Cragg, Senior Vice President, Operations; and Scott Moses, Senior Vice President, Offshore Products. Before we begin, we would like to you caution listeners regarding forward-looking statements to the extent that our remarks today contain information other than historical information, please note that we are relying on the Safe Harbor protections afforded by federal law. Any such remarks should be weighed in the context of the many factors that affect our business, including those risks disclosed in our Form 10-K and other SEC filings. I will now turn the call over to Cindy.

Thank you, Patricia. Good morning to all of you and thanks for joining our earnings conference call today. Our second quarter 2015 earnings remained in positive territory, but continued to be negatively impacted by the low crude oil price environment, particularly in North America and Well Site Services segment. WTI averaged $57.85 per barrel in the second quarter and have taken another leg down by $10.46 a barrel or 18%, ending at $47.39 as of July 20, 2015. At the time of our first quarter earnings conference call, held at the end of April, we believe that our Well Site Services business would find a bottom and exit the second quarter stronger than where we entered it. However, the onshore market continued to deteriorate throughout May and into June, leading to a larger sequential decline than was originally expected. The average U.S. rig count decreased 35% quarter-over-quarter, the backlog of wells drilled but not completed, grew, while pricing pressures persisted. For the second quarter of 2015, consolidated revenues and adjusted EBITDA declined 20% and 37% quarter-over-quarter respectively, representing decremental EBITDA margins of 38%, with Well Site Services leading the way down. Our 2015 results are coming off a record year in 2014, resulting in ugly year-over-year comparisons. Our second quarter Offshore Products revenues were a broader spot during the quarter, coming in within our guided ranges, with an EBITDA margin exceeding the high-end of our guidance. Bidding and quoting for our Offshore Products and services continued during the quarter, albeit at a slower pace. With backlog declining 14% sequentially, we reported a book-to-bill ratio of 0.63x, bringing us to a year-to-date book-to-bill ratio of 0.81x. At this time, Lloyd will take you through more details of our consolidated results and financial position. I will follow with more details by segments, and provide you additional comments on our market outlook.

Thanks, Cindy. During the second quarter we generated revenues of $269 million and reported adjusted net income of $7.5 million or $0.15 per diluted share. This excludes pre-tax charges of $1.7 million for severance and other downsizing efforts. EBITDA adjusted for the severance and other charges totaled $43 million. Focusing on our balance sheet and our debt capital structure, we ended the quarter with total liquidity of $498.4 million, which is comprised of $409 million available under our revolving credit facility, plus cash on hand of $89.4 million. Our liquidity increased $70 million from the end of the first quarter 2015. And we used our free cash flow to fund CapEx, repurchase stock and to reduce outstanding borrowings under our revolving credit facility. Our financial position remains very healthy, with our gross and net debt levels at June 30 totaling $157 million and $68 million, respectively. Our net debt to book capitalization ratio approximated 5% at June 30 and our leverage ratio using trailing 12 months adjusted EBITDA was approximately 0.4x. During the quarter, we invested $30.5 million in capital expenditures, the majority of which was associated with the projects that carry over from 2014. Capital spending during the quarter was about evenly split between our segments and related primarily to the ongoing facility expansions in the Offshore Product segment, along with the addition of completion services equipment deployed to service the U.S. shale plays. For the full year 2015, we expect to spend approximately $150 million to $160 million in capital expenditures. Our priorities are to complete our new Offshore Products facility in the U.K. and to continue to develop our two locations in Brazil. During the second quarter, we repurchased 359,000 shares under our authorized share repurchase program at an average price of $39.94 per share. And earlier today, our Board of Directors approved the termination of our existing share repurchase authorization that was scheduled to expire on September 1, and replaced it with a new share repurchase authorization for up to $150 million for the term of one year from today. In terms of our third quarter 2015 consolidated guidance, we expect depreciation and amortization expense to approximate $32.5 million, net interest expense to approximate $1.6 million and corporate cost to approximate $11.5 million. Our corporate cost in the second quarter of 2015 benefited from expense reversals associated with our short and long-term incentive compensation plans. Our 2015 consolidated effective tax rate is expected to average 35.8% for the full year, which equates to an effective tax rate of approximately 33.2% for the next two quarters. And at this time, I'd like to turn the call back over to Cindy, who will take you through our business segments.

Thanks, Lloyd. In our Offshore Products segment results were in line with or better than our projections and the guidance ranges that we provided in connection with our first quarter 2015 earnings conference call. We booked revenues of $193 million during the second quarter of 2015 compared to $196 million in the first quarter of 2015. EBITDA totaled $41 million in the second quarter compared to $43 million in the first quarter of 2015. Our EBITDA margin percentage averaged 22.3% for the second quarter of 2015, coming in slightly better than the 21.8% reported in the first quarter of 2015. The second quarter of 2015 was impacted by a sequential decrease in revenues from drilling and elastomers product, and the impact of $1 million of severance cost recorded, partially offset by increased production and subsea product sales. Bidding and quoting activity during the second quarter of 2015 continued albeit at a slower pace due to delays in award timing and project deferrals. As a result, orders booked during the second quarter only totaled $150 million, which resulted in a sequential backlog decline of 14% to $409 million at June 30. Our second quarter book-to-bill ratio was 0.63x, bringing our year-to-date 2015 book-to-bill ratio down 2.81x. We did not book any individual orders greater than $10 million in the second quarter. We are pleased to provide an update on our new manufacturing facility that we've been constructing in the UK, which is now nearing completion. We are planning for a grand opening of this facility in the third quarter. As we progressed into the third quarter, we believe that revenues in our Offshore Products segment will increase slightly to range between $185 million and $195 million. We are forecasting sequentially stronger revenue contributions from connectors, subsea pipeline product and production facility equipment, but we do expect to see further reductions in revenues in certain of our shorter cycle and consumable products, as our customers remain focused on cash flow preservation. It is still our strong belief that projects focused on production infrastructure will ultimately be sanctioned, but the timing is not without the risk of further project deferrals. We are maintaining our EBITDA margin guidance at 19% to 21% for the third quarter. In our Well Site Services segment, our second quarter results were impacted by the continuation of the decline in the U.S. land drilling rig count, customers not completing previously drilled wells and pricing pressure exerted by our customers. For the second quarter, we reported a 39% sequential decrease in our Well Site Services revenue, which totaled $86 million. This sequential decline in revenues was attributable to a 32% decrease in the number of completion services jobs performed, a 13% decrease in revenue per ticket and lower utilizations for our land drilling rig. EBITDA decreased 70% sequentially to $11 million. And EBITDA margins averaged 12.9% for the second quarter compared to 25.8% for the preceding quarter. Decremental EBITDA margins came in at 45% in this segment due to cost-cutting initiatives. Land rig utilization levels continued to decline in the second quarter and averaged 34%, down from 44% in the first quarter that is consistent with the guidance we gave you. We currently have 11 of our total fleet of 34 land drilling rigs working, equating to approximately 32% utilization. We are assuming 32% to 35% utilization level for land drilling rig fleet during the third quarter. If there is a bright side to this market, the pace of recent rig count decline has abated. However, the lower absolute level of U.S. drilling and completions activity that we are experiencing today, will continue to weigh on our Well Site Services results in the third quarter, with what appears to be a flattening and possibly the trough in the U.S. rig count, we estimate that third quarter revenues for our Well Site Services segment will range between $82 million and $88 million with EBITDA margins averaging 12% to 14%. In conclusion, the North-American markets that serve remain very challenged with depressed levels of activity expected to continue through the third quarter and likely throughout the remainder of this year. We will remain focused on managing our cost structure, controlling discretionary spending, enforcing capital discipline and seeking to take advantage of investment opportunities where those investments make strategic sense during this cyclical downturn. To that end we believe that Oil States remains well-positioned, both operationally and financially with nearly $500 million of liquidity to support our businesses. That completes our prepared comments. Loren, would you open the call up for questions-and-answers at this time please?

[Operator Instructions] And our first question comes from Stephen Gengaro from Sterne, Agee.

I guess two things. I'll start with when I look at the job tickets on the completion services side, I was a little surprised at the sequential drop off in light of some comments that others have made. Can you just sort of walk us through that? And then as we talk about that on the revenue per ticket, is that a mixed issue there? And just kind of help us understand what is happening there as well?

Yes, I will certainly try to do that. Certainly, the number of tickets that's reflective of activity; and overall we've been trending in a fairly tight correlation, our revenues have, to the decline in rig count, so the piece of me that says that it's both activity and pricing, so in another words we have somewhat outperform the rig count decline, because revenues track in a tight correlation and that include some pricing pressure obviously. So it's always a little bit allusive overall. There is certainly a mix effect. We've had some completion test substitution away from our higher technology, higher value added type products in favor of cheaper, lower completion alternative, there is always a bit of that, but again I don't know if I answered your question completely, but activity is trending in the same direction obviously as the rig count, but with revenues fairly mirroring the rig count I think we've slightly outperformed.

When you look at the, I guess, sort of the substitution effect of sort of maybe lower technology versus some of your offerings, is that dragging -- like how do you work your pricing decisions and structure around the possible substitution of maybe somebody else's?

Yes, I am really talking more specifically about our isolation tools. A lot of times, you can go with the higher pressure wellhead, you can go with a frac stack, there are different alternatives there. And those are bid in different basins differently. I mean, depending on the competitive landscape, particularly I would say on the frac head side, so you just have to keep your ear to the ground almost on a daily basis to try to understand that. Now, you know we also offer frac heads, so we can be competitive with alternative solution techniques as well.

And if I could slide in one more, when you look at the bid ask on the acquisition front, is there any change over the last three months?

I feel like maybe some of our targets, and the list is building. We have had some dialogue. It depends on whether you're talking Well Site Services or Offshore Products. We're not seeing as much on the service side yet. I don't know how much pain has to be felt before those emerge. But as you know, even in our own business our Well Site Services is down so hard, it'd be very difficult to try to monetize that business at the trough we are seeing some Offshore Products, but even they feel like that they are there, but I don't know if they're eminent. It kind of depends on that depth and duration of this down cycle, but I think the book is building. Maybe that's the better answer. But in terms of bid ask, I don't think I can have too much commentary there.

And our next question comes from Jim Wicklund from Credit Suisse.

It's hard for somebody to pay you based on your second quarter Well Site Run rate anything close to what you would think it would ultimately worth.

Well put. You got my drift.

Question on subsea, I mean, offshore, 63% book-to-bill, 82% for the first half, so we can see the direction. We saw what happened, FMC gave us some detail as to how that plays out, NOV gave us some detail on how that plays out, doesn't this implicitly say that your '16 and '17 revenues are going to trend down from current levels?

Jim, as you know, we've got to have a lot of flexibility when we look at these things. We have a base case and a downside case. And right now, both by varying degrees would suggest down results for 2016, but wide variation, and that is specifically because of the bid book and projects that are there. And the commentary that I want you to focus on was no projects awarded during the second quarter in excess of $10 million. So this is kind of recurring standard connectors. It's service-oriented work. It's in-and-out work, but no major orders. That doesn't mean we're not bidding on them, we certainly are. And so that the difficult time with all of this is that we don't know if they'd come in the third quarter, the first quarter, early next year. Although, there have been some announcements of projects either getting resurrected or coming towards closer to FID, if not receiving FID, that I think our overall guidance, and I think what you've asking me for, what is that, soft, whether you call it a forecast or a goal of 0.8x book-to-bill for the year still in play. And I'm going to tell you, its still in play, but it's just so hard to estimate when these things are going to come in the backlog, but just because of the second quarter with the overall lack of large project award, I'm not ready to back off of that goal.

And what percentage of all this, Cindy, is like you say longer cycle stuff versus what we've seen cut so much with the shorter-cycle stuff as everyone conserves cash. Can you give us an idea of the split though, because you're shortening up [multiple speakers].

Well, you've seen in Q1 and Q2 and that tells you what occurred, that short cycle stuff is quickly eroding out of our backlog and eroding out of our revenue stream to where you're going to find a floor, meaning that the sequential comps get a little bit easier. Q3 and Q4 of last year for Offshore Product, and quite frankly, for Well Site Services were record quarters, and so composite bridge plugs as an example, drilling diverter valves, there's a number of thing that I can talk about. Drilling FlexJoint those are going to work their way through the system. Then you're going to stabilize. I think that has stabilized the revenue contribution and stabilize kind of your book-to-bill as well. And then there is certainly the potential for the shot in the arm, because of some of the projects that are out there that are fairly broad based, but the Gulf of Mexico, Brazil and Southeast Asia that probably won't surprise you either, because that's where the activity is. But anyway is that is --

How much of your backlog is short cycle -- how much of your backlog is today is short cycle business?

First of all, we don't historically carry as much backlog in those businesses. I could look at it, but I'm kind of looking at my bridge plugs, then my valves. And I'm going to say, its $15 million to $20 million depending on what you define as short cycle.

On the Well Site end of the business, activity stabilizing, or at least it was when oil was stabilizing. We will see what happens now. In terms of ducts, drilled but uncompleted, you noted those in your comment about their having an impact. Have we started to drill those off and how many do you think there are?

Well, I think it's anybody's guess. We just had our Board meeting and we actually cited, I believe Bloomberg as a source that had estimated about 4,000 drills uncompleted, which I believe was about 10% of the wells drilled. Chris, do you have any added comments?

Yes. Jim, I think we're started seeing some of those jobs come on the board. So the recent downtick in oil, we'll have to watch and see the sustainability of some of those. I don't think the number has moved very much. It's pretty difficult to pinpoint on the exact number. But I don't think its being work down much.

And our next question comes from Marshall Adkins from Raymond James.

Let's spend a minute more on Well Site Services. It sounds as if, and again, I think a lot of this was probably predicated on higher oil prices and we're staring it on our screen today, but seems like things are bottoming, things should stabilized the back half of the year, that's what I heard in your commentary. Am I interpreting that correctly?

You absolutely are interpreting it correctly, and based on customer -- I'll just generally cut through the chase, and say, end of May I was still in pretty good. The rig count declines had pretty much stopped, and then we actually got rig count increase. We are sticky around $60 a barrel, and then of course, that's why I put my other comments down on what happened since the end of June. So I'll just it say it with caution in the air, in the sense that I felt pretty good that we have found a bottom in the May, June timeframe nominally not much better in July, but I could point to a green shoot or two, but I worry with crude level of $50 in the short term, so you can predict it as well as I can now. But the crude oil price decline is certainly attention grabbing.

That's what I figured. I just want to make sure I got it. On the offshore margins you gave us pretty good guidance there for Q3. As we look out over the next year, what could take that higher or lower? Are there more cost savings or streamlining to occur that might help it or is the possibility for lower throughput maybe down? So what could affect those margins looking out beyond Q3?

I can help you with that. And these are going to be probably obvious comments. But first of all I would like to just commend my team for managing margins so well thus far, and granted we're not falling off like Well Site Services are. But we've had some fall off in activity and we manage proactively, I think, very well to report the margins that we have thus far in the first half of this year. So it will be wrong of me not to acknowledge that. Now there are two to three larger bid opportunities out there that play into some of our key connector technology, that if we could get that in the backlog, particularly like Q3, early Q4, I think that helps us certainly as we go into 2016. That's a simple answer. Get backlog of your high-margin products. No shock there. But we're bidding it. And there's Shell Appomattox is out there, as an example, we all know that there is a project in the marketplace. So there are some very specific project activities in Brazil that we are on top of. And so that could really counter this backlog decline that we experienced in Q2. The second key elements there is, do we in fact get any type of U.S. land-based recovery, which could help our elastomers product. It's not a huge piece of our business, but in offshore product, the elastomer technology had some extension into land-based activity, just like Cameron and FMC and others. And so no surprise there. But I think those are the major two data points. I don't really want to focus on cost cutting as a solution, I'd rather have topline growth. We only trim when we're force to do so, based on our backlog and our activity level. But again there are some possibilities there that could give us some more positive output for 2016. We will know the answer to that by late third quarter or probably early fourth quarter.

Would those awards be more on the drilling side or the production-oriented side? It sounds like it's more drilling-related?

Production, production, production. Yes.

And our next question comes from Jeff Tillery from Tudor, Pickering, Holt.

I guess on the completion service businesses, I'm curious, if I look at the revenue per ticket over the last couple of quarters, it's down by about a-third. I guess, I'm curious, kind of relative contribution to that in term of just the mix of business versus pricing versus other factors kind of underneath the radar that I'm not thinking about?

Let me take a stab at it, and Cindy can weigh in as well. I think there are a few factors. First of all, obviously pricing goes into that as well. There is some product mix. I think we're seeing duration of jobs tighten up a little bit, as customers are running the well size a little more tightly than they have before, where job just were not out there as long frankly. I think all of those contribute to the drop in the revenue per ticket.

And I guess, I mean, there is probably not a very good answer for this, but I think substitution is having an impact. And so as we step into recovery, when do things like efficiency and safety and whatnot matter more? Is it early stage of recovery or do we need to see 100 rigs added to the mix before you think the customer is focused on those elements?

I don't want to infer that our customers are out there, taking more safety risks that are out there. Some of our products, if I can, just to be clear, part of the value is savings of rig time, savings of other service time at the rig side. And I think what Chris was trying to say, when all of those services get so cheap, it's a little harder to justify the incremental investment in the higher technology products. I don't think our customer who's out there is taking undue risk at the well site at this point in time.

And then last question just around the Offshore Products order side. You didn't book anything of substantial size in the quarter. I think I know the answer, but I wanted to ask the question anyway. Was there any sort of market share change in the quarter? I guess did you miss on something you thought you'd win or is it just the timing of what were just those --

Absolutely, not. One of the beauties of our product offering is they are somewhat unique in the marketplace. And we have a very high market share on a lot of them, where we have competitive market share, i.e., standard connector products are crane, we were getting our fair share of the work. And don't feel like we've exceeded market share there.

And our next question comes from Sean Meakim from JPMorgan.

On offshore, do some of the various subsea service JVs that we've seen in the last couple of months being out. Do those pose a competitive risk for Oil States or do you see opportunities there, as the value chain is trying to find ways to save cost and make more projects economic?

Well, I think that, overall, I would have write it either neutral to seeing more opportunities. And part of that is just simply put, our customers need to make money. And if we get more projects to come to the forefront, because they become more economic overall, that's good for not only us, but for the whole industry. Again, with somewhat of a unique product offering and product line, I don't think we would be advantaged by entering into one of these joint ventures. And to do so is almost saying that one, its installation contractor, particularly as it relates to our subsea product is so strong globally or in a given market that you want to align with that one. We have the beauty of supplying product to a variety of projects and a variety of customers, and we interact with all of the installation contractors. So I don't in anyway feel disadvantaged. I have acknowledged before, I think it dates back close to five years, where we contemplated entering into an alliance arrangement, not a JV, an alliance arrangement in a given geography with an installation contractor for just this purpose. But we concluded after discussions that we felt like that would disadvantage with respect to other installation contractors, and elected not to pursue it. Hopefully that is responsive.

And then sticking with offshore, are you seeing any delays in delivery request from customers at our backlog as we've seen from some other parts of that space?

No, we're not.

And our next question comes from Kurt Hallead from RBC Capital Markets.

I was wondering if you might provide some additional color on the Offshore Products for the quarter in the context of what was revenue at a backlog and what was book in turn?

I'm looking for my team here. I don't have that at my fingertips at this point in time, sorry.

And maybe as a follow-up on the well services side. Cindy, you provided the guidance range on the EBITDA margin. How does that mix between drilling versus well services? In other words, do you expect the second quarter drilling services, implied cash margin to remain flat in the third quarter, so that the variance on margin is all completion-related work?

I think the guided margins are consistent with our reported margins. For the most part, we guided [multiple speakers].

But the variability is around the completion work and not really land drilling. Like a 12% to 14% range that you provided.

I'm going to let Chris add to that.

We're all looking at each other. Probably the general answer to your question is, yes. Although, again, where we guided the utilization number for drilling, if a rig goes down or if we pick up extra rig, it will impact the margin at this level. Simply at the lower revenue levels, everything can impact it at a greater extent. So we've got a range for both, and it depends upon what the variability actually ends up being as far as what drives it of course. And the answer to your question is, yes.

And our next question comes from Chase Mulvehill from SunTrust.

I guess a quick question on your guidance. I guess your guidance -- I was kind of surprised that revenue was basically modeled or guided flat, but if you look at the rig count kind of just trending it down about 4%, if you kind of hold it flat from here. So are you assuming flat activities from here? Are you seeing completion activity outperforming land drilling activity? So just kind of help connect the dots there.

Yes, I will. Right now the visibility we have is July, basically. And so it's very specific to our own operations and there is kind of nominal type improvement that we're talking about, quite frankly can come in an individual geographic market. And right now, we support offshore as well as onshore. We're seeing, in July only, a little bit of improvement of contribution from some of our offshore work.

And so if you think about July on the completion services side, was it better than 2Q run rate?

Again, I'm thinking of it more in the context of was it better than the exit rate for the quarter. And I'd just say, normally better, but attributed to offshore more than land.

And so just thinking on completion services, if we kind of just do the quick math and look at basically your cash cost, so I just think your revenue minus your EBITDA and get cash cost of about $60 million associated with your completion services in 2Q. How much of that is fixed versus variable?

Well, the prior relationship was about 60% of our cost are headcount driven, meaning salary wages, benefits, plus travels that goes along with that. Obviously, our costs have come down as market activity has come down. I think that percentage might have weighted up a little bit higher, but we have not cut our workforce obviously to the degree that the rig count has come down at this point in time. So I hope that helps. But even cost outside of headcount driven costs, some of it is truck mileage fuel. We drive all over the earth supporting our customers on locations, R&M associated with the level of activity of equipment, et cetera. So a lot of the costs on a percentage basis are in fact variables.

And then real quick on Offshore Products, if orders don't pick up from here, 2016 looks like its going to have some headwinds on the revenues side, where revenue from backlog could be down pretty materially. So as we kind of think about the mix as revenues and backlog could be down materially next year, maybe you get some stabilization in the shorter cycle business and aftermarket business. So how should we think about the margin profile as we move into 2016 or maybe you want talk decrementals rather than margins?

Actually I think I'm just going to wait on that. I don't like hypothesizing 2016 without knowing what my backlog is. So I'd rather defer that until at later conference call, if you don't mind. We've gotten great historical data on how we perform through the cycle on our margins. I was just looking back to the last five years and I think it'd give you a real good indication of how you choose to model those margins.

So it's fair to assume that nothing that you see right now that you would kind of break below kind of the 17%, is kind of I think where you troughed in 2010?

I specifically was looking to 2010 as an indicator for me, yes. I don't remember exactly 17%, but that was thought process I have. We keep running five year models about base case and downside, and that is exactly the kind of trend line I would look to.

And our next question comes from Blake Hutchinson from Howard Weil.

First question for Chris, just wanted to talk a little bit about Jeff's earlier question with regard to what you were seeing in order to believe with regard to perhaps substitution trends. And I understand its very hard to data mine a business, its falling off as much as it has in the first half, but as you look back in the first half of the year, just want to establish that you actually do feel like that there have been some preference changes in terms of equipment usage that have also hurt the business and after its all said and done, you kind of just look the same as you did in 4Q, it's just more that thought process more of touring just general weakness in the market than really any clear cut trends in usage?

I think it's more of a short-term issue, Blake. If you look at our revenues for the second quarter, as you know, we've always said ballpark 70% to 75% of our revenues in the completion services comes from our product lines, where we have some proprietary advantage as we've defined it. That relationship still holds true. So I'm not concerned about any long-term trends of something supplanting our technology.

A couple of quick ones. Just with regard to the near-term margin guidance in Offshore Products, does the U.K. facility itself, and the introduction of that have any drag on result?

We hope not. We planned very carefully for smooth transition. There is a little bit of risk. So I don't think it would be material, but certainly there is some relocation type from one facility to the next. We hopefully have buffered. We're going to support our customers, we're probably carrying a little more inventory of our standard connectors right now to try to prevent or smooth any types of transitional type activities. And so just overall, I don't expect any material disruption or impact to the margins from it.

And then, I don't want to get overly technical, and I realize you said you didn't necessarily have the numbers at hand, but I was trying to get a feel for just simply the simply the short-cycle business transition in Offshore Products from 1Q to 2Q. And even if you're just couching, it's just the drilling and elastomer business. I mean, were we talking kind of 10%, 20% negative comparison, just kind of broad strokes on how this short cycle might have compared to the backlog degradation?

Well, what my team is trying to pull back together, and I believe what they come up with is that when you include short cycle and services combined was about 20% and about 80% was backlog driven. So again, relative to nine months ago the contribution from the short cycle and services is clearly down.

And our next question comes from John Daniel from Simmons & Company.

I know you guys don't like providing guidance beyond the current quarter, but I want to just see if you will opine on this. But let's assume we do stay at stable activity levels, specifically within Well Site Services, and we stay there for next three to four quarters. Are there any steps that you can take at this point beyond maybe cost reductions that could lead to margin recovery or is Q2, Q3 sort of reflective of a stable environment over the near-to-medium term?

We're watching everything on obviously a daily basis, trying to find as many efficiencies as we possibly can from third-party procurement to internal-type efficiencies. Let's face it, John, at some point, you hit diminishing impact. And what we've said all along, the crude oil price environment we find ourselves in feels non-sustainable. At some point in time, our hope it is not three to four quarters in duration, but certainly if it is, we'll be fine. We're prepared for that eventuality. I'm not sure that everyone is. There are levers to pull, but again our headcount is down dramatically in this business. We've adjusted variable base pay. And it gets harder and harder to pull those levers once you get to a certain level of activity.

I don't know if you touched on this earlier, so I apologize if it was discussed, but did you give any color on expectations for orders in Offshore Products for Q3?

Not specifically Q3, but the question I think most people want to know is kind of how you're going to end the year. We had a really strong Q1 bookings relative to the street, Q2 was softer. And while I'm not giving guidance, I've set kind of a soft goal of the 0.8x. So I think some of the commentaries around is that's still achievable. And right now, we're not going to back off of that based on the bidding and quoting activity that's out there.

And then last one, the very minor. You noted that 11 rigs are running today, at this point, do you have visibility in terms of is that rig count going up or down over, say, the next two to three months?

We're guiding to flat. Just soon as we put a rig or two out, we have another rig or two come down. So it's just on the margin at this point, but guiding to flat.

And our next question comes from Jeffrey Spittel from Clarkson.

We have covered a lot of ground, so let's keep it short and sweet. Cindy, you referenced back in May and June when the world was looking like a little bit of a happier place, maybe can you talk us through, were you starting to see any evidence of some customers gravitating back toward more the proprietary equipment and technology in the completions business or was it maybe a little bit too early to expect to see that happen?

We haven't really seen it. And we had a modest I think, 19 rig improvement, which was just last week. So I'd just say there's no trend line changes at this point.

And then the project slippage that you talked about in Offshore Products, we hear a lot from the subsea vendors that they've gone back and rebid these projects. Is that also consistent with what you have been doing or for the most part have you been able to maintain the current bids, and maybe the slippage use due to kinks elsewhere and the supply chain?

We absolutely rebid them, but I don't want to infer that that's all price concessions. A lot of this is reconfiguring, redesigning of the order that we got in Q1 is very indicative. Well, I think we've been bidding that for two years. And it probably came in at a third of the original values. If you think about a line, how many future connects might you have into that export line and do you build those in now or do you them in later, it's still the same field, the same project, but there are ways to redesign around those, and obviously scale those projects over time. And so I'm sure there are some pricing type concessions, but we typically try to get the benefit on the cost side to offset that, but then there's a lot of what I could call redesign, reengineering. And over the last five to seven years, I didn't know how many versions of metallurgies could go into a project. And every time I would ask, well, is this project going to be just like X, Y or Z that we did last year, and the answer was always, no. So we weren't getting economies of scale and benefit from prior experience. And I think those are the -- it's somewhat operator behavior that is adjusting as well. And proven metallurgic, proven technology, proven designs in the field were not being repeated, and repeatability is how we obtain efficiency.

And our next question comes from Michael Lamotte from Guggenheim.

Cindy, I don't know if you or Lloyd want to take this one, but a couple of questions on the cash side quickly. It looks like receivables coming down have been a good source over the last couple of quarters, but inventories are relatively flat from fourth quarter levels. Is that a function, because the majority of that is Offshore Products? And is there any work to be done on that front in terms of creating a source of cash?

I'll actually speak to that. It won't surprise you that that has been a focus of mine. The working capital benefit that we have received has been substantial in the first half of the year that has come, as you point out, largely from accounts receivables, which I am pleased and proud of. It was a very focused effort for us. Inventory, I believe, was actually up, about $5 million in total, about evenly split between well site and offshore products. As it relates to well site and they sound of kind of counterintuitive, but recall that it was just October where we had record peak rig counts. And so certain ordering activity, some of which was coming from international destinations within our order book that has come into inventory, and quite frankly a little bit into CapEx as well that we didn't see prudent to cancel. We're in a strong financial position. We don't need to do that. And so that CapEx I think will trail off a bit, as we go into the second half, and certainly inventory purchase activity pretty much come to a standstill. So I do think you'll see that trend down again in well site services. I've done an in-depth look in offshore products. Again not a huge bill, but one might say why is it coming down. But a lot of this is very much project specific inventory that is destined to backlog projects in various locations. And I think I mentioned a little bit earlier, possibly to John or Jeff, that we are carrying a little more in terms of standard connectors in the U.K., so that we don't have a customer service interruption of any type, as we relocate from Aberdeen into the Heartlands facility in the third quarter. But my comment there is absent improved backlog and kind of timing, we probably do think that inventory will begin to come down a little bit.

Quickly on CapEx, you talked in past about not putting capital into cap star. But I'm wondering, as we go through this downturn and we hear some of the other contractors and certainly the equipment companies talk about, everybody wants an AC rig, everybody wants a Class A rig. How do you feel about the quality of the fleet? And are you at all having to reconsider the idea of putting money into those and make them more competitive?

Well, I don't mind commenting all about cap star, and we never said we would not put capital in the business. I think we maintain state-of-the-art. So relative to what we have, they are shallow water rigs. They do only maximum light horizontal work, but we will not run a rig, if it is not well maintain. So there is maintenance CapEx that we are spending on an ongoing basis. Through the first six months, we invested about $9 million of CapEx in our fleet of rig, despite the fact that we only have on average now about nine running. I would rather stack them then have them run poorly. And so that is not what we'll do. The good news is, even at these fairly, low is not draconian levels of utilization. We're still generating cash from the operation. We generated about $3 million of cash in June. And we will absolutely maintain the fleet.

And our next question comes from Stephen Gengaro from Sterne, Agee.

Just one quick follow-up. Could you just walk us through quickly when you think about your own stuff versus another company, how you guys think about that at this point in the cycle?

By another company, do you mean acquisition?

Yes, potential acquisition candidates versus just buying more OAS.

Well, I do feel like that at these low levels that we are experiencing, we need to grow the topline. And it has been in the past, whether it's organic. There just aren't many organic opportunities right now, given the downturn in activity. I do think that with the passage of another six months or so, there will be some consolidation opportunities. But it's not lost on me that that there is market consolidation occurring and the big companies are getting bigger, and some of the small companies are going to be disappearing. And so I do think that consolidation is a favorable trend, if they emerge as we think that they will. Our stock, it's always an alternative, particularly at these low prices. I think Lloyd announced we kind of re-upped our share repurchase authorization. But at these low price levels that authorization is 10% of our outstanding stock at today's prices. So I think there is benefit from that too. Historically, when we rank those capital allocation opportunities, we've put organic, first. The type of M&A that we do, i.e., the way we price it, value and integrate it, it proves to be second. And it gives topline growth and helps us leverage a very strong operation and a strong management team. There are times, however, when our stock is valued that such that we will buy those shares in. The good thing is we've got a lot of financial flexibility today to do just that. But we do believe there is going to be M&A opportunities that emerge. And if you say, my body language today, I want to be prepared for that.

But Stephen, we have done that, like we did in the first quarter, when we bought MMC and did share repurchase.

Thank you. We have no further questions at this time. I will now turn the call over to Oil States International for closing remarks. End of Q&A

I appreciate it, Loren. I really just want to thank everybody for continuing to follow us. I know it's kind of a tough sledding, it's a busy day, but this industry is cyclical and it's never dull. So we look forward to our next call and hopefully more stable and brighter outlook. Thanks so much.

Thank you. And thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.