Pioneer Energy Services' (PES) CEO Stacy Locke on Q2 2016 Results - Earnings Call Transcript

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Pioneer Energy Services (NYSE:PES)

Q2 2016 Earnings Conference Call

July 28, 2016 11:00 ET

Executives

Anne Pearson - Investor Relations

Stacy Locke - President and Chief Executive Officer

Brian Tucker - President, Drilling Services

Carlos Peña - President, Production Services

Lorne Philips - Chief Financial Officer

Analysts

Brian Uhlmer - GMP Securities

John Watson - Simmons

Daniel Burke - Johnson Rice

Marshall Adkins - Raymond James

Operator

Greetings and welcome to the Pioneer Energy Services Second Quarter Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Anne Pearson, with Dennard-Lascar Investor Relations. Please go ahead.

Anne Pearson

Thank you, Stacy and good morning everyone. Before I turn the call over to Stacy Locke and Lorne Phillips for their formal remarks, I have a few of the usual items that we need to cover. First of all, a replay of today’s call will be available by webcast and also by telephone replay. You will find that replay information in this morning’s news release. Just as the reminder, information reported on this call speaks only as of today, July 28, 2016. So any time-sensitive information may not be accurate at the time of a replay.

Management may make forward-looking statements based on beliefs and assumptions currently available to them. While they believe these expectations are reasonable, they can give no assurances they will prove to be correct. They are subject to certain risks and uncertainties and assumptions that are described in today’s news release and also in recent public filings with the SEC. So if one or more of these risks materialize or should the underlying assumptions prove to be incorrect, actual results may differ materially. Also please note this conference call may contain references to non-GAAP measures. You will find a reconciliation to GAAP measures in this morning’s release.

So now, I would like to call – turn the call over to Stacy Locke, Pioneer President and CEO. Stacy?

Stacy Locke

Thank you, Anne and good morning everybody. Joining me here in San Antonio today is Brian Tucker, President of our Drilling Services segment and for the first time in this capacity, Carlos Peña, President of our Production Services segment. Carlos has been with the company for almost 8 years now and served in a number of capacities, General Counsel, Director of Safety – which has been a very, very important role to the company, because many of you know we have been a leader in safety for years and Carlos has played a big role in that. And he has also been very involved in our strategic thinking and strategic planning. So, we are excited to have promoted him to President of our Production Services segment and of course, Lorne Philips, here, our Chief Financial Officer.

Talking about the second quarter as we alluded to in the last conference call for the first quarter, we knew this was going to be a tough quarter. Although we did end up fairly close to our expectations, it was still a very challenged quarter for us. Our Production Services segment was down a little more than we had anticipated and each business within Production Services was down a little bit, well service, wireline, and coiled tubing. From an activity perspective, even with the recent pullback in oil prices, I do think that the second quarter is the bottom. And I will explain that further by looking at each of these business segments here for a second.

Looking at the drilling segment first, we have definitely seen some positive developments in drilling. Our West Texas division has grown from 3 rigs to 6 active rigs. We had relocated a rig from the Eagle Ford to the Permian, while it was still under a term contract in the first quarter. That went to spot. We had several new clients and we have now established it with a client that we think will keep it for the rest of the year and probably into the following year. So, that’s a very positive development. As I mentioned on the last call, we had just taken our last newbuild rig that we had stripped the contract off of and assigned it to an existing AC rig in the Bakken. And we were able to place that, as well, in the Permian and that looks to be busy for the rest of the year, probably into next year as well. And we’ve just recently relocated one of our earning, but not working rigs from the Bakken to the Permian, just as the earning not working was closed exploration. And that rig is now spudded and working in the Permian and – with an operator that has a long drilling program as well. So we are very pleased to see those opportunities developing.

We are having similar success in the Marcellus Utica area. We have renewed one of the contracts that expired during the quarter. There was a one year term that expired and we rolled that forward for an additional year. We do see an opportunity there to grow the market like we have done in the Permian. We expect to go to – from 3 to 5 rigs by the end of the third quarter and that’s also anticipating mobilizing 2 AC rigs from the Bakken to the Marcellus Utica area. So by late Q3, mid-September or so, we should be working 13 rigs, up from 11 rigs today.

We also have additional upside. We have still remaining 3 AC rigs in the Bakken that can go to work. And we have SCR rigs, both pad-capable walking rigs here in the U.S. and in Columbia. In Columbia, like the U.S., the chatter has increased. The bidding activity has increased. And we have become more optimistic about our ability to put rigs back to work there possibly in the third quarter, more probable in the fourth quarter of this year. So, that’s an improvement.

Turning now to the Production Services segment, as I previously mentioned, well servicing utilization dropped, hourly rate declined 6.6% in the quarter. So, revenues were off as a result of that and profitability off a little bit. Heavy rains and flooding, particularly in the south, did impact that business as it did the other Production Services businesses, mostly in April and May. And we saw improvement at the end of the quarter, both from bad weather and improved oil price driven activity. While oil prices have retreated a bit recently to the low 40s, we’re still seeing slightly improved activity level and feel better about our third quarter and fourth quarter prospects. A slight firming of the oil price to the mid-40s, upper 40s would sure help build a foundation under this kind of improved outlook that we have.

Turning to wireline, similar to well servicing, it was down in revenue, down in margin, but we did see a market pickup in June and in July – carried through to July. We are still seeing it today. That bodes a pickup in maintenance and remedial work as well as completion work. Some of the DUC, drilled and uncompleted wells, were started to be completed, so that helps. And then we have had new rig activity, just more perforating work as well. Bidding and outlook I would say is definitely better today and I believe we are probably one of the most active wireline providers currently in the U.S. market. So, we are staying busy, moving lots of trucks around, doing lots of different types of jobs and definitely seeing an improvement there.

In coiled tubing, like well servicing and wireline, we are a little off in utilization, off in margin, but we are seeing the same increased bid activity, more optimism, further discussions about future work and things are looking much more positive. I think one clear development in the coal business is we have actually worked some of the larger pipe, the 2 3/8, the 2 5/8 pipe and that’s showing promise there, so, generally more optimistic about improvement in the third quarter and the fourth quarter and looking into ‘17.

With that, I will turn it over to Lorne to give a brief financial recap.

Lorne Philips

Thanks, Stacy. Good morning, everyone. This morning, we reported revenues of $62.3 million and adjusted EBITDA of $3.6 million. Our reported net loss was $30 million or $0.46 per share. Excluding the impact of the valuation allowance on deferred tax assets, related to net operating losses and the after-tax impact of loss on extinguishment of debt, our adjusted net loss was $20 million or $0.31 per share. In late June, we amended our credit facility. While we expect to see higher activity in the second half of the year, like Stacy mentioned, we felt it was prudent to proactively work with our bank group. The amendment reduced the commitments from our banks by $25 million to $175 million, while also providing more flexible covenant provisions, including moving to a minimum EBITDA covenant from the fourth quarter of 2016 through the second quarter of 2017. We currently have $95 million outstanding and $17.3 million in committed letters of credit under $175 million revolving credit facility.

Looking at Production Services, revenues were $34.3 million, down 18% from the prior quarter and gross margin was 16%, down slightly from 17%. As Stacy mentioned, all businesses were impacted by activity declines and some weather impact, particularly in April and May, prior to some pickup in June. Well servicing utilization was 40% and the average rate per hour was $485 in the second quarter. That compares to 44% and $519 in the first quarter. Coal tubing utilization was 20%, down from 24% in the prior quarter.

Drilling revenues were $28 million, down from $33.2 million in the prior quarter and utilization was 39%, based on average fleet of 31 rigs. Drilling margin per day was down slightly to $11,879, primarily due to lower earning not working revenue as compared to the prior quarter. In early July, we mobilized one rig from North Dakota to the Permian and will likely mobilize another 2 rigs from North Dakota to Appalachia in September. For these mobilizations, we expect to incur approximately $1 million in costs in the third quarter. The reduction in margin per day for the third quarter as a result of these mobs is estimated at around $1,000 per day and is reflected in the guidance we issued earlier this morning. These costs should not repeat in the fourth quarter.

Since late 2014, we have received termination notices on a total of 19 drilling rigs. That resulted in an aggregate $62.8 million of termination payments, which are recognized ratably over the term of the underlying contract. We recognized early termination revenues of $7.1 million and $4.4 million in the first and second quarters of 2016. And we will recognize the final balance of $1.8 million in the third quarter. The revenue days associated with earning not working rigs in the third quarter are expected to be 17. The revenue associated with the final earning-not-working rig was accelerated into July as that rig went to work on a new day work contract. And finally, we’ve received all of the cash payments associated with early termination notices.

We have 31 rigs in our fleet today. Currently, 11 of our 16 AC rigs or 69% are earning revenues and the remaining rigs are idle. Of the 11 rigs that are earning revenues, 7 of those are under term contracts in the U.S. The roll off of the 7 rigs working under term contracts is as follows: one is up for renewal in the fourth quarter of this year and we are currently in discussions to renew that. One rig is up for renewal in the second quarter of 2017 and again feel good about our prospects there for renewing it. One rig is up for renewal in the fourth quarter of 2017 and four expire in 2018. The three rigs currently in contract in Columbia are suspended pending an improvement in commodity prices, and while suspended, the rigs do not earn revenue.

Turning now to our company-wide expense items, G&A expense was $15.3 million, down 8% from the prior quarter. For Q3, we expect G&A expense to be in the $14.7 million to $15 million range. Depreciation and amortization was $28.9 million, down slightly from $29.8 million in the prior quarter. We expect D&A to be approximately $28 million to $29 million in the third quarter. Interest expense was $6.4 million in the second quarter and we expect that to be up slightly to $6.5 million in the third quarter. The effective tax rate in the second quarter was 6%, down again due to evaluation allowance taken against the deferred tax assets, which is related to – primarily related to domestic and foreign net operating losses. Excluding the valuation allowance, the effect of foreign currency translation and other permanent differences, our tax rate would have been in the 35% to 37% range. Year-to-date capital expenditures were $13.2 million. We now estimate full year 2016 capital expenditures to be approximately $27 million to $29 million.

With that, I will turn it back over to Stacy for his final comments.

Stacy Locke

Thank you, Lorne. I will take just a second here to touch on our forward guidance and kind of how we view the outlook for the remainder of the year. I would say that we believe that the rebalancing of the global oil market is very much intact that it’s more believable today than it was 3 months ago and we are seeing that reflected in a number of ways. The rig count has been steadily improving. So, the E&P community feels better about the future and is spending capital again. We have seen actual better relative oil prices, which pushed into the ‘50s. I think provided some of the E&P community to hedge positions, which strengthens the market a bit. We have seen definitely more bidding, more conversations about future work in the marketplace. So, all-in-all, we are fairly optimistic about what we are seeing at this point.

Looking at the Drilling segment first, I think we feel real good about the backlog of work that we built and the opportunity to put additional rigs to work, certainly in the latter part of the third quarter and the fourth quarter. But sadly, our earning not working revenue is, as Lorne mentioned, falling off. It will be gone during this quarter. And then we do have to absorb some hefty mobilization costs as we move rigs to markets that offer more promise. So, we will have to absorb that in the short run. So, our guidance for drilling utilization is going to be down slightly in the third quarter, 35% to 38%, kind of in that range, but as I have mentioned, it will be up in the fourth quarter. Margin per day will be kind of – you will have the earning not working reduction and also the mob costs reflected there, so we are guiding average margin per day $7,800 to $8,200 a day for drilling margin.

On the Production Services side, we are going to forecast a pickup, that’s based on what we saw in May and June pickup activity. I think higher rig count leads to more work. Clearly, we have a lot of the drilling uncompleted activity that’s picked up and it’s helped our business. And we have seen a general pickup in the maintenance or remedial work in, really, all these businesses just due to the slightly-improved relative oil prices. So, we are going to guide revenue up for the Production Services segment of 10% to 15% with a slight margin improvement back to ‘17 maybe as high as 19% of revenues. I think the net of that guidance is certainly – I think a positive EBITDA. It’s not a big EBITDA, but it’s going to be a positive EBITDA for the third quarter. And revenues should be at least flattish, maybe up slightly.

So with that, I will conclude the prepared remarks and would be happy to entertain questions. Thank you.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Brian Uhlmer with GMP Securities. Please proceed.

Brian Uhlmer

Good morning, gentlemen.

Stacy Locke

Good morning.

Lorne Philips

Good morning.

Brian Uhlmer

I want to start off on the Production Services side, I was curious as you called out the weather a little bit. Did that have an impact on the mix of what rigs were working or working higher priced rigs at 24/7, etcetera that caused this price decline or was that price decline a good apples-to-apples comparison, sequentially?

Lorne Philips

I think on the – you are talking about well servicing and I think – while quarter-to-quarter, the rate – hourly rate was down 7%. I think really if you look at the end of the first quarter, it was only down at most a couple of percent in the second quarter compared to the end of the first, so I don’t think the weather, from that perspective, impacted the pricing so much. It was more just activity. We had several rigs that were flooded in that you couldn’t get to. And so we just lost that business for a period of time.

Brian Uhlmer

Right. But you’ve got a decent spread of work that gets higher hourly rates just trying to see if that was captured, if that was an issue? So that makes sense now. Going into your guidance, into Q3, is that uplift going to be all activity at flat pricing or does your guidance imply that you get a little bit of pricing improvement or pricing goes down and activities in excess, can you walk through that?

Lorne Philips

Yes. I think it’s really activity driven. I think it would be early to suggest we are going to be raising prices in Production Services right now, but we see it more as activity.

Stacy Locke

Okay, that’s all I have. We are seeing a little more opportunity for a 24-hour work, which had got pretty slim there. And so – we are – like today, we have three working on 24 hours. With 7 more conversations, that’s probably going to go up a little bit, and that generates quite a bit more revenue than a daylight working rig.

Brian Uhlmer

Got it. And was it fair to say that your stacks count is going to remain the same as just increased utilization on the already working and crewed up?

Stacy Locke

Yes, we are not anticipating pulling stack rigs out at this point.

Brian Uhlmer

Okay. Now under that backdrop, why would the margins only go up to 17%? Shouldn’t we get higher incrementals to hit the higher end of your range? And what are the roadblocks to not hitting that 19% higher range?

Lorne Philips

Well, Brian, that’s why we give the range, right, to say we would like to get higher incrementals, but it’s a – there is some art to it, not just science. So, yes, there will be some incremental as activity picks up, but there is a – on the art side of it, it does depend on what that mix is in some cases between the type of work you are doing and 24-hour work and completion versus just more remedial maintenance. So, that’s where the – you are trying to estimate it.

Brian Uhlmer

Okay, thanks. I am not sure if that was one question or three questions, so I will turn back over to other folks in the queue.

Operator

Thank you. Our next question comes from John Watson with Simmons. Please proceed.

John Watson

Good morning, guys.

Lorne Philips

Good morning.

John Watson

I wanted to start in drilling, I noticed three rigs whose contracts have expired but are continuing to work. Can you give any incremental color on how the dayrates changed?

Stacy Locke

Well, pricing is soft, I would say, bracketed kind of in the 15 to 17 range in kind of the Texas markets where labor is a little bit lower and then maybe 16 to 18 range, up in the northern part of the markets where labor is higher. It’s kind of where the ranges are for us at least. There are lower rates out there, for sure, in both of those markets. We have been able to keep our pricing fairly firm, based on just the performance of the equipment. So – but there are lot of dayrate ranges out there. The broad market range would be a wider range than that, I think.

John Watson

Okay, that’s helpful. And then in Q2, do you have the cash margins excluding the early term payments handy?

Lorne Philips

Yes. I think probably the right way to look at it would be about $9,000 a day, if you adjust for everything that went on in the quarter, backing out earning not working, and that also compares somewhat to our guidance. The midpoint of our guidance is around $8,000 a day, which does include that $1 million of mob cost, which is probably around about $1,000 a day impact, so that’s how you might get from our guidance to the working without the earning not working.

John Watson

Okay, that’s for Q3. Do you have the number for Q2 handy? What it actually was?

Lorne Philips

Maybe, I didn’t understand your question. It was in Q2 about $9,000 a day.

John Watson

Okay, okay.

Lorne Philips

Yes. And then I was comparing that to Q3 guidance.

John Watson

Okay, perfect. That’s all I have got. Thanks, guys.

Lorne Philips

Thank you.

Operator

Thank you. Our next question comes from Daniel Burke with Johnson Rice. Please proceed.

Daniel Burke

Good morning, guys.

Stacy Locke

Good morning.

Lorne Philips

Good morning.

Daniel Burke

I wanted to ask about a comment I saw in the press release, but I don’t think I heard you all allude to in the prepared commentary. The comment on Production Services being softer in July, I guess I wanted to confirm was that specific to a portion of Production Services or the overall business and then how does that incorporate itself into the sequential guide for Q3?

Stacy Locke

Well, I think that’s more of a July 4 effect. That’s just historically is a time where people take a pretty good, at least a week off for the most part, so activity just falls off and it kind of lingered a little bit this year, longer than normal. So, I would say the first couple of weeks of July, was pretty soft. Carlos, you have anything you want to add on that?

Carlos Peña

I think that’s fair. With the Brexit and some of the declines in the price of oil, I think that may have contributed a little bit, but well servicing seems a little bit off in the early part of July, but it’s coming back and wireline has been pretty healthy, but July 4th clearly had an impact.

Daniel Burke

Okay. And then again, the comment also mentioned the pullback in oil price. So just to be clear, did you mean July was softer than June or softer than something like a Q2 average run rate?

Lorne Philips

Yes, fair question. Softer than June was the comparison that we were looking at there.

Daniel Burke

Okay and presumably activity was picking up as the quarter advanced. Okay.

Stacy Locke

Yes.

Daniel Burke

And then one more on Production Services, it’s unfair because nobody has much of a crystal ball right now. But is there any reason that – early call on Q4 for this year, I mean, I guess, typically there is enough seasonality in Production Services that the business steps lower, although at least there is some potential, we have got rising drilling activity to support a part of that business? I guess it’s not a fair question, but I wanted to ask it just in the context of thinking about the EBITDA basket that you guys are now operating against here in the second half of the year.

Lorne Philips

Yes. I will jump in and say something and Carlos can jump in as well. Our view is that, as you go into the fourth quarter, we think it will be a fairly constructive outlook. And so there will be a seasonal impact in the fourth quarter, but I feel like there is a very good likelihood that, that’s overcome by positive increasing activity levels. And so feel like it’s a pretty constructive outlook on the second half of the year recognizing that the recent pullback in oil prices is there, but we still feel like, as Stacy said, the oil demand/supply will work to the benefit in the second half of ‘16.

Daniel Burke

Okay. And then last one from me back on the drilling side real quickly. No surprise that the interest in the uptick to date has been on the AC side, but Stacy, just curious if you are having any discussions on the SCR side?

Stacy Locke

We are, particularly in Columbia, where we have some prospects out there. As you might imagine that every potential job has every contractor in the country bidding on it for the most part, but we have a little optimism that we may pickup a job or two even in this quarter, don’t know, not in our forecast, because it’s just too uncertain and there is so much competition, but we have got a little clearer picture that one or two of the rigs that are on standby could activate in the fourth quarter. So, those are all SCR rigs. And then we do have – we are having now conversations on occasion about potential SCR work. So, nothing has come to fruition. Brian, anything you want to add on that?

Brian Tucker

The only color I would add is just that most of that – the challenge is not only – it’s, obviously, a very competitive market, but also to bring some of these SCR rigs or any rigs that have been stacked for a while out of stack condition, you need to be able to get enough work or have confidence that you could have enough work on the back end of the wells to justify the startup costs. So, with a lot of our long-term clients, particularly in South Texas, we just haven’t been able to piece enough wells together to have it really make sense, but we are certainly having more conversations along those lines than we have had recently.

Stacy Locke

You have seen in the market SCR rigs that have gone back to work. So, it’s happened out there and of course some of the mechanical rigs have gone back to work as well. So, we think that’s coming in time. Hopefully, it will hit in Columbia for us, first, but we are certainly going to be bidding the SCR rigs, because they performed great, bottomer pad-capable walking rigs. So, we think that opportunity will present itself, in particular, as oil prices firm up.

Daniel Burke

Got it. Thanks, guys. Thanks for the time.

Stacy Locke

Thanks.

Operator

[Operator Instructions] Our next question comes from Marshall Adkins with Raymond James. Please proceed.

Marshall Adkins

Good morning, Stacy. Quick question or follow-up on the SCR, I believe you mentioned like AC pricing in Texas 15, 16 a day, little higher up north. How would SCR leading edge pricing compare to those?

Stacy Locke

Typically, in a market like this, pricing is fairly compressed. And for us, we wouldn’t really want to put it out much cheaper than that kind of maybe the low end of that range that we mentioned. We have seen it in past cycles before where everything compresses and you are able to get roughly the same rate, some operators just like the SCR rigs. Brian, would you agree?

Brian Tucker

Yes. Marshall, I will just add. We don’t have a lot of data points on that, but I would agree with Stacy. As these AC rigs rate have compressed and are lowered, there’s not going to be a large gap there, and again, most of those opportunities are going to be based on prior performance with the clients that are deciding to take your rig because of past experiences.

Marshall Adkins

So, if – let me just pontificate here on how the cycle might unfold. It sounds like as demand starts – we are expecting a nice recovery next year and then into ‘18 as well. As that goes up, the AC rigs go to work first, they tighten up, rates go up there, and then it sounds like you’re saying we should get a pretty nice bump in the utilization for the SCR rigs? And then you create more of a gap between SCR and AC, as the ACs get fully utilized, does that make sense to you?

Stacy Locke

I would say, it’s more complex than that. I think there is going to be quite a bit of differentiation within the very, what’s now, very broad AC market. And so I think that non-pad-capable AC rigs are going to be at a competitive disadvantage to pad-capable SCR rigs. So, there is that issue. And then I do think there will be a preference broadly speaking, for more walking-oriented rigs versus skid-oriented rigs and we have some of both. So, it’s just – based on our own experience, there is many applications now that it’s just hard to service those pads with a skid-oriented rig. So – and then on top of that, I think there is an emerging class of AC rigs, that I think are in the highly competitive category. And those are rigs that can rack more pipe, have a bigger pressure capability on the mud systems, can move pad-to-pad in very competent timeframes. Those I believe will price disproportionately to good AC pad-capable rigs. So, you have got lot of complexity in there, but I would certainly expect to see some of our SCR rigs come in long before all these AC rigs get picked up. Would you add any color on that, Brian?

Brian Tucker

Yes. The only thing I would add, Marshall, is that as you look at a very competitive bidding process right now, the clients today are, wanting 7,500 psi mud systems, they are wanting – walking rigs is the clear preference there. And so as you look at the ability to meet that demand right now, a lot of the large contractors will be able to take equipment out of inventory. Let’s say you need to add a third pump, a third 1,600 horsepower pump, you will be able to, for a while, take that equipment out of inventively with limited capital investment. But at some point, that inventory gets used up and then you have got to put quite a large capital investment to get the rest of your fleet ready to performing. And also not all those are walking or skidding capable at this point either. So, at some point, you will have a group that will need minimum capital investment to go out and work in a way that our clients want. And after that group is out working, I think it will be a kind of different situation and that’s where we will hopefully see rates start moving.

Marshall Adkins

Right, that’s very insightful. Okay. Coming back to Brian’s first question or one of them on the Production Services, your guidance is up 10%, 15%, I think shocked all of us. And that’s pretty darn healthy. Just to recap the reasons for that pretty substantial improvement next quarter sounded like you are shifting to some 24-hour ops, maybe weather was a part and perhaps a little mix? Did I get that right or do you want to add more to that?

Brian Tucker

Well, we do have improving weather and it certainly did impact Production Services in April and May of the second quarter. With the relative improvement in oil prices, for like example, well servicing, 24-hour work either for completion or for bigger workover-type jobs that almost went away in late Q1, Q2. And with the improving oil prices and I would even put the $42ish a day oil price range and upward where we are today, certainly upward from here, you will see a pickup in more of that 24-hour completion work and remedial recompletion type work. So, that’s what we are anticipating there. And then on the wireline activity, most – that activity picked up due to improvement in oil prices across the board, across the basins in remedial work. And then on top of that, the DUC work started picking up and also rig counts improving. So with improving rig count, those wells aren’t going to be DUCs, they are going to get completed. So you’ve got completion activity following rig count, you’ve got drilled and uncompleted coming into the mix, in addition to improved remedial type services. So, that’s pretty clear. We are seeing that very visibly, in particular, in big pickup in June, July and continuing conversations today. So, we are optimistic about that. And then specifically in coil, we haven’t done a large pipe job for a long, long time. Well, we’ve now done some 2 3/8 work. We have done some 2 5/8 work. We are in conversations about potentially additional work in the big pipe. And we had a falloff in our offshore work. We did a little bit in the second quarter and even early third quarter on our offshore small pipe work, but that’s picking up. We are going back to work now in the offshore. So, these are visible signs that we are seeing. I think we would all feel better if oil would migrate back up $45, $48. But I think in the environment we are in today, we are still seeing that improvement. And I am hoping that these operators have hedged some oil when they had the chance there, when we peaked over $50 for a little while. I think they did. I think we have heard that. So, that could help a little bit, but we like to see a little bit of recovery in oil, doesn’t need to go back into the 50s, but certainly some improvement in the 40s would help.

Marshall Adkins

Okay, last one from me. As you know, we are looking for robust recovery in oil and we are looking for the rig count to double next year. In that environment, help me understand what’s your working capital needs and CapEx needs and that kind of stuff, just so I am working out the cash flow, if you can explore that a little bit?

Lorne Philips

Well, we guided on CapEx this year that we think we will come in, in the $27 million to $29 million range. I think that from a routine and maintenance perspective, for this year’s level of activity, it’s probably about $15 million to $18 million range. Next year, I would expect it to be about the same ballpark, but it is a little dependent as – like, how many SCR rigs would we put to work, how many – and including Columbia. So, the higher activity levels on the drilling side, particularly if Columbia goes back to work, that routine of maintenance could inch a little higher. On the Production Service side, I guess, in the scenario where – it depends how aggressive the recovery is. We have talked in the past, I think on the call but I think our estimate on kind of deferred, if you took all the units out of the stack, which would be a very aggressive recovery and that would be gradual for us. But we think we would probably have $5 million to $7 million of deferred CapEx cost to get back to running all our capacity in the Production Service side. So, that would be gradual, of course.

From a working capital perspective, I think we – I would say, it probably can be lumpy, but using something where you look at say $0.05 to $0.07 for every $1 revenue increase has been in the range of how things have worked. We would expect our investment in an upturn to be less than what we pulled out, because we had a decent amount of working capital in Columbia at the time the downturn came. We pulled a lot out of Colombia and that had tended to be – while we always got paid, it had tended to be a very long payment process. And I think with the customers that we are talking to today, our sense is that, that would be improved from what it had been. And we probably – we would very much like to get back to working 7 to 8 rigs there, but that’s not really – we are thinking 4 to 5 is what we are targeting. And so I don’t think we would have the same working capital investment. So from that perspective, you can look at the revenue growth, make some assumptions on the investment. And I just say that when we did this amendment, we tried to factor in an outlook that was improving as well as other scenarios to make sure we were okay in various situations. And we feel like we have adequate liquidity to take part in the upturn and – so that’s a long answer.

Stacy Locke

Let me add a little bit to that, Marshall, because you could see we’re not flush with capital, we are – we are continuing...

Marshall Adkins

I am not sure anybody is.

Stacy Locke

We are continuing our efforts to sell non-strategic, non-core assets and I think Brian about has one of our held-for-sale rigs could close this week. Is that right, Brian?

Brian Tucker

Right.

Stacy Locke

That’s a non-walking SCR rig and we continue to have conversations – certainly, as oil prices have peaked up a little bit, we’re getting more opportunity there. And we – there is a handful of U.S. rigs and a few in Columbia that we would like to sell, if we were able to achieve appropriate pricing kind of like we sold some for during last year. So we are still seeing those opportunities and we continue to want, desire to sell some assets that are non-strategic to us. So, that will help put a little capital into the coffers.

Marshall Adkins

Thanks, guys.

Operator

Thank you. [Operator Instructions] There are no further questions. I would like to turn the floor back over to Stacy Locke for closing comments.

Stacy Locke

Okay, thank you all very much for participating on today’s call and we will look forward to visiting in the future. Thank you.

Operator

This concludes today’s teleconference. You may disconnect your lines at this time and thank you for your participation.

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