Pioneer Energy Services (NYSE:PES) Q1 2016 Results Earnings Conference Call April 29, 2016 11:00 AM ET
Anne Pearson - IR, Dennard-Lascar
Stacy Locke - CEO
Lorne Phillips - CFO
Brian Tucker - President of Drilling
John Daniel - Simmons & Company
Daniel Burke - Johnson Rice & Company
Waqar Syed - Goldman Sachs
Jason Wangler - Wunderlich Securities
Praveen Nara - Raymond James
Good morning and welcome to Pioneer Energy Services' First Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. [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. Thank you. You may begin.
Thanks Matt, and good morning, everyone. Before I turn the call over to Pioneer's CEO, Stacy Locke; and to CFO, Lorne Phillips for their opening remarks, I have a few of the usual items to go over.
First of all, a replay of the call today will be available by webcast and also by telephone replay. You'll find the replay information for both in this morning's news release. Just as a reminder, information reported on this call speaks only as of today, April 29, 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 and information currently available to them. While they think these expectations are reasonable, they can give no assurances they'll prove to be correct. They are subject to certain risks and uncertainties and assumptions described in today's release and also in recent public filings with the SEC. So if one or more of these risks materialize actual results may differ materially.
Also, please note on this conference call we may make references to certain non-GAAP measures. You'll find a reconciliation to GAAP measures in this morning's news release.
Now I would like to turn the call over to Stacy Locke. Pioneer President and CEO. Stacy?
Thank you, Anne and good morning. Joining me here in San Antonio is Brian Tucker, President of our Drilling segment, and Lorne Phillips, our Chief Financial Officer.
As we had expected, the first quarter was a tough challenging quarter. Capital spending was off as we had anticipated it would be which inevitably leads to lower utilization and a tougher pricing environment. The oil price shock in February to sub 30 levels, exacerbated the situation and pretty much pushed everything even a little bit lower.
So it was a challenging quarter, kind of happy to have it behind us and today it does seem as if may be the worst is behind us, although the momentum of that quarter will carry through into the second quarter, but if thus seem to be turning a bit and I’ll try to illuminate that further as I go through each of the four core business lines.
On the U.S. drilling side, we're seeing that market as stable and improving. We just recently backed within the last couple of weeks mobilized our latest new build out of the rig-up yard in Houston to the Permian and West Texas to begin work there.
That was a rig that we built under term contract and during the year last year we strip the contract off of it and assigned it to an existing AC rig in the Bakken which left us able to market that rig to a new client which is exactly what we've done and so our goal is to put these rigs out and keep the contract term short and that’s what we did there.
In addition looks like we've secured work for one of our spot rig that also happens to be in the Permian that we mobilized from or was taken by the client that had it under term contract originally to the Permian and we kept it there in the Permian. It's done a number of different jobs and work looks like its lining up with that rig. At this point of least, it's not firm, but it looks like it will stay busy into next year.
In addition we just received a renewal on another expiring contract up in the Utica and that will go forward for an additional year. So things are moving along as we get hoped. I ‘d say that chatter in the space has improved and we’re probably going to putting we have two more rigs that are on early term that will expire in the third quarter.
I’m fairly confident by that point that we will be able to replace those rigs with working rigs. So we'll keep -- we're currently at 11 rigs actually working to earning, but not working I am pretty confident by the third quarter we'll have those other two rigs or two more rigs working to replace those are really not working not falling off, and I’m pretty confident by yearend we'll have pretty much all of our 15 latest generation AC rigs back to work.
So we're starting to see that bit of an improvement out there. I would say that it's not all incremental demand although there does appear to be some incremental demand, but it is high grading by operators, high grading of rigs with a little bit of great capability than some of the existing rigs out there.
But as you all know, pricing remains suppressed in the Southern market were in the 15,000, 16,000 a day range in the Northern where wages are higher maybe 17.000, 18,000 a day. So, very, very depressed pricing, but our lease activity does seem to be bottomed and beginning to improve.
In Columbia, that market remains depressed, almost no rigs working in our class in the 1,500 higher horsepower class environment just essentially no rigs working and that includes a lot of rigs like ours that are technically under contract, but generally the Columbian market does follow the movement of the U.S, market basically which follows oil prices.
So, we expect it to get better. We have three rigs under contract. One of them is scheduled to go back at the end of the second quarter but we don’t have that official notice yet and we don’t know therefore that it will happen, but we do expect that market to improve as the oil price market firms up.
Turning now to the production service side of the business, first to well servicing, I think well servicing was kind of the surprise for us in the quarter. It's been very, very adorable over these patchy year, but with that price decline that we experienced in February to sub 30, we saw just an immediate reaction from operator delaying maintenance, pushing back recompletions and minimizing 24-hour work, weekend work.
And so it definitely had an impact. So, we saw that in our well servicing as you could see in the press release and whatever that happens the competitors get more aggressive, there is less work to go around and so pricing has been just really at an all-time low as competitors try to get market share, and try to get it at our expense because we’ve already been kind of the market share leader.
But thereto we’re beginning to see with the pricing back into the mid-40s, we're seeing that activity begin to firm up. Still going to be competitive on a pricing front, but we were expecting to see rigs going back to work and on a relative basis, I think our performance and our safety will allow us to outperform again like we’ve done in the last number of years there.
It looks as if some of the drilled and uncompleted wells are going to start in process to be completed and that will help our other services, but also well servicing. So as long as oil prices hold in here and/or improve, I think we're working on a recovery there.
Same kind of perspective on wireline. We saw a pullback in the quarter like in well services, but we're getting -- we're beginning to see signs of improvement. I think the level of request for proposals is way up and that's both on taking ducts out of -- heading ducts into completion and some new rig activity completion work.
So that's exciting. We have not seen that for a while. So that we still have a great footprint across the major basins in the U.S. So we're there already. We've kept a solid staff and so we will be ready to go back to work as people allow us to.
We in both well servicing and wireline and in coil, we have continued to further reduce our cost, but due to the difficult first quarter, so I think we have our cost structure in real good spot and so as we see activity pick up, pricing is going to be low. It's going to be at the bottom, but as activity picks up down the road, then pricing should firm up as well. So we're pleased with that.
The one business that we aren’t sure we've seen any turnaround yet is in coil, I think we're doing very solid work, a steady work albeit at a low utilization level and I don’t think that we have the visibility into that business line yet to call it at turn, but I’m pretty confident that it will follow well and wireline has this recovery unfold.
So we're feeling a little bit more optimistic. We certainly enjoy having oil prices in the mid 40s. We expect them to kind of stay in that level and gradually improve through the course of the year and setting up for a very nice 2017.
So let me turn the call to Lorne and he will give you a little more financials overview. Thank you.
Thanks Stacy. Good morning, everyone. This morning we reported revenues of $75 million and adjusted EBITDA of $6.4 million. Excluding the impact of valuation allowances on deferred tax assets, our adjusted net loss was $19.2 million or $0.30 per share.
Some key points for the quarter include the following, our capital expenditures were $5.5 million of which $1.7 million was primarily related to drilling rigs delivered in 2015. We continue to estimate 2016 capital expenditures to be approximately $25 million, which includes $8 million of previously ordered equipment, which will likely be fully paid by late second quarter or early third quarter of 2016.
We reduced net debt during the quarter and our cash balance at the end of the first quarter was $18.7 million, an increase of $4.5 million from yearend 2015. That was due to payments from early terminating contracts and some working capital benefits offset primarily by our bond interest payments that we made in March.
As Stacy mentioned significant cost reductions were made in all businesses in the first quarter through headcount and compensation reductions.
Finally based on our expectation of a moderate recovery in the second half of 2016, we believe we will maintain compliance with the covenants under our credit facility. However to be prudent and also to ensure we maintain adequate liquidity, we feel our next step likely would be to pursue a credit facility amendment.
Turning to the business segments now, production services revenues were $41.8 million down 22% from the prior quarter. The gross margin was 17% down from 19%. Again as Stacy mentioned, all the businesses were impacted by continued declines in pricing and activity.
Well servicing utilization was 44% and the average rate per hour was 519 in the first quarter of that business. That compares to 55% and 562 per hour in the fourth quarter. Coal tubing utilization was 24% just down slightly from 25% in the fourth quarter.
Drilling revenues were $33.2 million down 35% from the prior quarter and utilization was 46% based on an average fleet of 31 rigs. Our drilling margin per day was down approximately 1,500 to 12,018, primarily due to idle rigs in Columbia as well as lower earning now working revenue as compared to the prior quarter.
If you exclude the benefit of margin from rigs earning but not working, our margin per day would have been approximately 9,300. In the first quarter we reported average consolidated operating cost per day of 13,313 and that includes items the impacts from Columbia, operator pass through items and other mobilization costs.
So for the purposes of comparing average operating cost per day in the U.S. with current day rates, we estimate that those cost per day would be approximately 12,000 to 13,000 on any incremental operating rigs that we put to work depending on the operating location.
Since 2014 we have received termination notices on 19 rigs totaling $62.8 million. The termination payments are recognized ratably over the term of the underlying drilling contract. We recognized $49.2 million and $0.3 million in 2015 and 2014 respectively. We recognized $7.1 million in the first quarter and expect to recognize $4.4 million in the second quarter of 2016 and $1.8 million in the third quarter of 2016.
The revenue days associated with earning not working rigs are expected to be 182 in the second quarter and 72 in the third quarter. We have received all of the cash payments associated with early termination notices.
We have 31 rigs in our fleet today and of those 31 rigs, 94% are pad capable and 52% are AC. For our 23 drilling rigs in the U.S. 16 are AC and seven are SCR. Currently 13 of the 16 AC rigs or 81% are earning revenues and the remaining rigs are idle.
Of those 13 rigs earning revenues, 10 are under term contracts in the U.S. Of those 10 contracts -- of those 10 rigs under term contracts, two are earning but not working. So the roll-off the eight working rigs under term contracts is as follows.
One is up for renewal this quarter, another one in the third quarter of this year, another one in the fourth quarter of this year and one is up for renewal in the fourth quarter of 2017. The remaining four expire in 2018.
For the two rigs currently earning, but not working, both of those are AC and both of those expire in third quarter of 2016. In Columbia, revenue was approximately $1.1 million down from $7.2 million in the fourth quarter. Additionally EBITDA in Columbia was negatively impacted by a onetime $0.8 million net wealth tax incurred during the quarter.
In the fourth quarter of 2015, two of the three rigs under contract were suspended at the client's option pending the recovery and commodity prices and in February of this year, the third rig was suspended as well. The three rigs are currently idle and they do not earn revenue during the suspension period.
Turning now to our company wide expense items, G&A expense was $16.5 million down 3% from the prior quarter. For the second quarter, we expect G&A expense to be in the $15.5 million to $16 million range.
Depreciation and amortization was $29.8 million, down from $35.4 million in the prior quarter due primarily to the full impact of previous fixed asset and intangibles, impairments, drilling rigs held for sale and de-sale of rigs that we had in the fourth quarter, late in the fourth quarter.
We expect D&A to be approximately $29 million in the second quarter. Interest expense was $6.3 million in the first quarter and it is expected to be flat to slightly up in the second quarter.
Our effective tax rate in the first quarter was 7% due to a valuation allowance taken against deferred tax assets primarily related to domestic and foreign net operating losses.
The ability to realize our deferred tax assets is dependent on the generation of future taxable income and due to losses incurred in recent years and a loss expected for 2016, accounting rules limit our ability to consider taxable income that is projected in future years and therefore we're required to establish a valuation allowance to offset the future tax benefit associated with the net operating losses carry-forwards.
And while these net operating loss carry-forwards have been reserved on the company’s financial payments, they have not expired and they remain available to offset future tax obligations.
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. We currently have $95 million outstanding on our $200 million revolving credit facility with an additional $17.3 million committed in letter of credit.
With that, I will turn it back over to Stacy for final comments.
Okay Lorne. Thank you. Just one note of clarification, the one term that renewed this quarter is the one we just extended for one year, correct. So that's been now extended for a year, which is good news.
As I think in the call last quarter, I had mentioned that I thought Q1 was probably going to be the bottom, I think you can see from our guidance and our commentary that it now looks fairly -- we're fairly confident that the second quarter will be the bottom in this cycle and as long as oil prices don’t collapse again, it looks like we're on a upward trajectory from here.
So on the guidance just to reiterate what's in the press release for the second quarter I think we're -- we feel very comfortable on our utilization in 40% to 43%. I think as we look out to Q3, Q4 that we’re going to have as I mentioned before a couple of earning not working rig fall off that accounted in that utilization and we're hoping to have those replaced by working rigs and then pick up more utilization maybe in the fourth quarter.
On a margin basis, ex the earning not working, we're pretty solid in there at 8,300 to 8,800 a day. I think as we put more rigs back to work through the remainder of the year that that will average down a little bit because those rigs are re-priced at a lower market rate out there today. But very stable it looks like for our drilling operation.
On the production services side, also as I previously mentioned, we saw a more challenged market develop during the quarter, which will cause the momentum to push revenues down in this quarter. Hopefully towards the middle later part of the quarter we'll see activities pick back up and offset that a little bit, but we’re going to guide for a 10% to 14% reduction in revenue.
But we think we're able to hold the margin firm will all the cost cutting that we put in place. So we're going to call that own margin in PPS firm to slightly up. So that's good. I think the cost cutting we've done has been very effective on that regard.
So anyway, at this point, I think that will conclude our prepared remarks and we will be happy to answer any questions anybody might have.
Thank you. We will now be conducting the question-and-answer session. [Operator Instructions] Our first question comes from John Daniel from Simmons & Company. Please go ahead.
Stacy, just quickly going through some of the comments, you mentioned that cash margins are getting lower as the rigs get repriced and go back to work. At this point and an all else being equal world, do you see the cash margins dipping below $7,000 a day in either second half 2016 or first half 2017?
No, I don’t think -- I actually haven’t done that math, but I don’t anticipate they will get that low because we still have a solid base of the rigs under term contract that are much, much healthy rights.
And we're talking about just depends on how many rigs I guess we put back to work if we start having an opportunity to put an bunch of the SCR rigs back to work then it could, but for right now just in lot of the market we're seeing, we really anticipate putting our 15 higher-end AC rigs back to work first.
Possibly we'll put some SCR rigs back, but we're not counting on that at this point, but if that does happen and we put all our SCR rigs back, we could be a little bit work. I don’t -- I still don’t know if that would get us below that.
I'll add to that, I think in the U.S. I think that would be likely -- you would have to put more SCR to work, but as you said but I also think in what could impact that on a consolidated basis is in Columbia what happens there in terms of putting rigs back to work or not.
So, that if we don’t put rigs back to work and put SCR that -- I think that could fall below that, but we do expect Columbia to improve as oil prices improve. So, hopefully we’ll put some back.
And then you mentioned the rig pricing I think of $15,000 to $16,000 a day in the southern region, and like $17,000 to $18,000 in the northern region, are we going to assume then that when you sign up those rigs, the one along the Permian, the one reselling in the Utica, that the pricing fell within those levels? Or is that a true spot market on it?
Yeah, well I don’t have a -- I don’t ever comment on specific contracts, but I think I’m just saying that to us that’s kind of where the range is today. So, if you're booking rigs today, is should fall in that range.
Okay. Fair enough. Lorne, one for you. The Q2 depreciation of $29 million, about $800,000 lower quarter-over-quarter. Should we just cascade that in from a modeling standpoint given the low CapEx? Or would it hold firm at $19 million? Just trying to get some color there.
Okay. On the last part of your question, I was having trouble hearing it, but I think you're asking about the depreciation is it going to stabilize around the $29 million mark going forward.
I think I would probably leave it there trending. It will I think trend down slightly after the second quarter, but the big change there was getting the full roll in of all those items that were impaired in the sales of rigs. So absent the sale of additional rigs, it should be little less volatile I think going forward.
Thanks. I will turn it over to others. Thanks guys.
Our next question comes from Daniel Burke from Johnson Rice & Company. Please go ahead.
Good morning, guys.
Stacy, Lorne, you all gave all the detail on the rigs. I just wanted to make sure I kept track of the US side. At update, you had three spot -- in addition to the term, had three spot AC, three idle AC, and then Stacy, did you talk about one in the Permian going back? Would that be a fourth spot rig? Am I keeping that track and drop you to two idle AC?
Well let me see if I can get it right, we have two including the new build that we just took to the Permian. We have two spot rigs in the Permian and including the new build that we just took out there and those we think are going to be committed through the end of the year.
And then in the Appalachia we have one spot rig and we think that's going to stay busy also through the end of the year and then while I mentioned we have two earning not working and then two stacked AC rigs of our newer generation and then we also had one stacked that's not what I would include as part of the 15 rigs.
We have one other that's a 2,000 horsepower AC rig and it's a little less competitive compared to other 15, but those four AC rigs that are stacked two of them are earning not working through the third quarter and then two are down right now.
And what I was saying is those that are not working are going to fall off during that third quarter and I think by the time they fall off we will have those other two rigs working.
And then once those rigs come off early term, I’m pretty confident we’ll get them working before the end of the year. So that will be -- that two incremental rigs working, assuming no SCR rigs and the other AC rigs doesn’t go back to work the 2,000 horsepower.
Does that make sense?
Yes, that's a helpful rendition. Can you talk about the volume of -- I don't know if you can phrase it that way. Can you talk about the incre-level on the rig side that you see right now?
Well, I think as I mentioned I would say it’s a combination -- well there is certainly is talk of incremental rigs, but I don’t -- there is maybe a little action in that front, but a lot of what’s going on for us right now is replacing other AC rigs that are able to be replaced.
And so it’s a little bit of high grading by operators because they really want the most efficient rigs available and if they can get them now particularly these day rates are going to do it.
Okay. And then maybe my follow-up for Lorne. It looks like if we do the adjustments for early term for Q1 and Q2, the rig margin guide is off sequentially $500 to $1,000 a day. Just wanted to understand, is that simply reflecting the shift towards more of a spot day rate weighted fleet in the US? Or is Columbia more of a burden in Q2 than it was in Q1? Just wanted to understand those two relative factors and how they're playing out.
It's primarily moving to spot in the U.S. with more rigs. There is a probably a little bit you do lose -- we’re not planning on revenue in Columbia. So you're going to lose about $1 million of revenue there, but the primary reason for it is the rigs in the U.S. working on spot at the lower rate.
Yeah. Okay. Alright, guys. Thank you for the time.
Our next question comes from Waqar Syed from Goldman Sachs. Please go ahead.
Thank you. On the production services side, the wells servicing side, the demand that you've recently seen, is it coming from completion work or is it mostly work-related demand?
I think we'll call it's a combination of it like what I referenced earlier, the RFPs that are coming in for the well servicing bunch that’s going to be a combination of rig activity completions and drilled and completed wells being completed. It's probably weighted towards the duct, but it’s also I think in anticipation of what I’m describing here on the drilling side of a little bit more rig activity. So that’s how I would answer that.
On the well servicing side it’s going to be both. We saw in the first quarter a lot of deferred maintenance, people that normally are maintaining all the time just put it off and not spend anything that was a big expenditure and we’re already starting to see people come back and do the big work-over and do the maintenance and then that will also come to bear on completions as well because in some cases you'll drill out.
We'll get may be a little bit more. One or two more rigs back on 24 hour work. So I think it will be a combination.
And recently, where are you seeing this demand? Is it more spread out or is it primarily in the Permian?
Well, on the production services side for us its everywhere but the Permian because we’re not in the Permian because of the pricing and so that would be a combination of all the other markets for the most part. On the drilling side we're seeing I would say more activity in the Permian. I’d say number one, but closely followed by Marcellus Utica.
Okay. Alright, that sounds good. And in Colombia, what is your view and what oil price is needed there to maybe reactivate the rigs?
Well, I think that we’re hearing murmurs already of some rigs being reactivated there and so I think that we're kind of at that level that gets some planning going and I think that we could stay in this 45 and gradually improve it from there, that you'll start seeing people work.
It takes time to plan there and so we don’t have a lot of optimism for the second quarter, but may be by the third quarter, we expect to see some utilization and more bidding opportunities.
We're in a number of dialogues with a variety of clients. We’ve got the three rigs under contract with one operator that is temporarily suspended, but indications are at the end of the second quarter one of those rigs should go back to work, but we’ll have to wait to see.
And then possibly the other two could go back in the third quarter -- we just -- but there again we have to wait and see and then will be bidding for work with other operators as well which we’re hearing more chatter there as we move these oil prices back into the 40s. So we're -- it's pretty -- the patterns are very similar to the U.S., when the U.S. starts picking up, Columbia picks up.
Okay. Is that relationship that you've seen in the past as well or is this is -- you think in this particular cycle, they're going to be acting much quicker?
Well, I think it's been the historic cycle. I think it mimics. When the U.S. goes down, Columbia goes down. When the U.S. picks up, Columbia picks up. So we’re expecting that same thing to happen here. It's all oil price driven.
They desperately need to produce more oil there and so we’re pretty optimistic and for us we’re excited now because now we’ve diversified our client base a little bit. We previously in the last cycle had all eight of our rigs with one operator and it's kind of hard to have leverage when you are in that situation.
So we’re not going to go back that way. We’re going to keep diversified and we’re still trying to downsize that footprint a bit. We don’t really want eight rigs in Columbia. We would like to be three to four operating rigs there.
And so we still have a goal to sell three to four rigs and downsize that footprint but we've been a top performer for eight years in that country and when they go back to work, we’ll go back to work.
That's great. And then in the U.S., as you mentioned, a few AC rigs that you can put back to work. In your view, what would it take to raise prices on those rigs? What kind of supply and demand needs to exist in the marketplace to get pricing moving up?
Well, I think that -- I think you'll see a lot of differentiation within the AC fleet on pricing. The rigs that deliver the greatest economic return to the operator I think we'll see that and I think all 15 of our rigs are competing in that top 15% of the AC market because we're the only guy out there that can move right now today and two to two and half days.
We were the only contractor out there that’s got all 2,000 horsepower mud pumps and 7,500 PSI fluid in. We're the only one that has -- we’ve been add racking capacity of over 24,000 feet of pipes. So, we’ve given the operators what they want to optimize your efficiency and so those rigs in the universe of AC rigs are not many and so those rigs I’m sure will see price improvements this year.
And it's probably not going to 5,000 a day, but I think you could see it go up 500,000, $1500 a day before the end of this year because those are the ones that the operators want. Those will be the first rigs to go back to work.
Is that demand for these rigs confined to a few operators, or is it pretty widespread for these type of rigs?
It's very wide spread.
Yeah, it’s independence and the big guys are like everybody wants that efficiency.
Waqar, and I would just add, this is Brian. I will just add that as we're seeing that demand for these kind of rigs, not only in the Permian but the Appalachia region as well with a lot of rigs out there that really can't drill use those and so the type of rig we have has been a great fit there.
But as far pricing different I don't know, we're seeing it that much right now. What we're seeing is the fleet we have is Tier 1 and they see with 75,000 PSI mud systems are the ones that are being able to continue working in a pretty challenging spot market. So we’d some success there and as the rigs come out, I think these rigs will start to see some differentiation on the pricing as well.
Okay. Great, thank you very much.
Our next question comes from Jason Wangler from Wunderlich Securities. Please go ahead.
Hey, good morning, guys.
Curious about the four held for sale rigs from last quarter, if you had an update where that process is at this point?
Yes, we’ve got the four held for sale rigs and no real change, they don’t have and we're really looking at all avenues. We're in conversations all the time about asset sales. We're as active as we can be there and really no change.
And quite honestly it got a little quite in the first quarter when oil went below 30, the people we were talking to quit talking and now we're seeing a little bit of resurgence of discussions going again and it just -- it's going to improve as oil price improves the opportunity to move those assets.
At good note we're not going -- we're not willing to fire sell them. They're good assets. We’re going to wait, take our time to get paid an appropriate price for.
I certainly can appreciate that and that's good color. Just curious, labor is something that a lot of folks are talking more about now. And with your commentary of hopefully getting those four rigs back out into the market later this year, could you maybe just talk to what you're seeing on the labor front now?
Obviously, I'm sure it's just we're still trying to right-size our businesses. But as you look to maybe be able to staff up and get those rigs running, what you're seeing internally and what you may have to do to make that happen from a labor perspective?
Yeah Jason, this is Brian. I think we're probably unique in the space -- in this area particularly on the drilling side. We sold 32 rigs last year. Got a big presence of labor in North Dakota, in Texas as well.
So, we have I don’t see it being really a challenge at all on the drilling side for two reasons. One because we're just smaller quality rigs that will be coming back to back to work, but I think also because of a lot of things we've been able to achieve in the course of rebuilt and the safety performance that we’ve had I think employees want to work for a company that treats them right and gives them a good safe place to work and we’ve had success on the drilling side at the lowest recordable rate 2015, had the same success non- interaction service.
I would say from my perspective, I think on production service side will be a little bit more challenged in that staffing and that they have seen the same year of productions that we've seen on drilling.
That’s helpful. Thank you. I’ll turn it back.
[Operator Instructions] And our next question comes from Praveen Nara from Raymond James. Please go head.
Hi, good morning guys.
I just had a couple of quick questions. On the Colombian rigs, just to make sure, when those went on standby, about what oil price did that come at? It seemed like it was around $40, $45, right?
When they started stacking…
Yes. When they went off and they went on standby?
That’s a good question. Few of them were going off very late in the fourth quarter and that third one went off in February. So yes it was, I think it was in the low 40s I want to say around then. Obviously during the time they were talking to us about it, oil price was moving a little bit up and down.
Right, okay, okay that’s helpful and then…
I think just -- I think what the important thing there is what did they think is going to happen beyond that point. I think in the fourth -- I think your question was if they won’t work in then at $45 why would they start working now at $45 and I think its outlook.
In other words if you’re pessimistic on oil prices, even though the prices are in the low $40s you're not going back to work. You're going to be little rigs off whereas its point where today, if your perspective is a little more optimistic about oil prices even though it’s the same price, you're likely to start planning to go back to work.
And I would guess that it would be that direction where perhaps -- and maybe their delay takes too long. But if maybe you do get something back to work in late Q2 because oil prices are back at the level where the discussions started going the other way.
Well that’s what our indications are. We'll have one rig back possibly by the end of the second quarter but we haven’t got a firm commitment on that yet.
Right. And then in terms of the production services guidance, and it depends on how Q1 shaped up. But it seems like there's not a whole lot of April, May, June uplift in terms of April maybe being the bottom or March being the bottom. Is that fair or am I doing my math wrong?
I think you -- I think we're assuming probably very, very moderate uptick in activity, but it’s pretty moderate -- it’s not much. We think a lot of things that Stacy was talking about the increased bid activity and some of the increasing interest in doing this work that we're hearing from customers is going to be late.
As we said in the press release it's really going to be late Q2 or early Q3 when you start seeing that flowing through. So, we haven’t built too much into our guidance.
And it’s going to be very price dependent because to get it you are going to have to be right there barebones pricing. So, it’s not going to be -- you're not going to be cascading and bunch of cash flow, it’s not going to be real strong cash flow out of those things. So, it's just going to be -- we're just got to get things back to work first and then chase follow with some pricing.
And just to make sure, we’re clear on it. That being said we would -- our expectation with that guidance is that June is better than April.
Right. That makes sense. And then my last question is on the non-drilling services side. Just a follow-up on the prior question. In terms of EMPs trying to lock in longer term rate and lock in these low day rates, how do you think about working at spot rates for longer, still making pretty good money and that willingness versus the trade-off of being able to play the spot market down the road?
Would you be willing to enter into a one to two year contract maybe one year but from a two-year contract at spot rate to make sure that you're getting that work?
I would say we just signed a one-year contract for an extensional one my guess would be that’s probably the last one we'll sign that we'll really be interested in staying six months or less because it's very low margin work and these are extremely capable rigs.
So, we're not in our minds being paid for what we should be paid for that quality of performance and so we’re going to be interested in moving that rate up a little bit.
So, we would probably not bid a two-year contract and more than likely unless we get a much higher rate we're not going to bid another one year.
That’s perfect. Thank you very much guys.
Our next question comes from John Daniel from Simmons & Company. Please go ahead.
Hey guys. Thanks for allowing me back in. Stacy, can you discuss the shift, if any, to 2 5/8 inch coil and how that may impact or not impact your operations if you feel like you need to make that transition?
Well, we do have a 2.58 inch coil that will be operable in May. So we are there. We only have one unit capability and then we have 2.38 inch units and then we have a bunch of two inch and then smaller.
And so we'll assess that market as it develops and that for the last six months it’s been the sub 2-inch market has kept us going. A lot of maintenance work with that small pipe market that’s been where the majority, some 2-inch but very little 2 and 3.8 inch but I do think will be able to, will like to see. We're hopeful we'll be able to get that 2 and 5-inch unit busy and if it works out like we think then we could look at adding more capacity there.
Would you say that the retrofit, if you will, was at a customer request or are you guys just trying to be proactive?
No we were being proactive. We knew we had customers out there that, that would use it. They've told us they would use it and so we were -- we’ve tried to have a full breadth of offering for that service and like before we were 2 inch and smaller and we had too clients that wanted 2 and 3h.
So we added 2 and 3 inch same on the 2 and 5 inch, we are trying to be a full service provider and so, we’re trying to have what the clients might want.
Okay. And then on the well servicing, the change in the rate per hour, how much of that would you call out as being a true price cut versus less 24-hour work, less work over activity?
Hard to quantify that but there is definitely a price cut in there because our competitors have just gone barebones on pricing to try to get our work and so we’ve had to cut pricing but clearly we were running, 8, 10, 11, 12., 24-hour job before, we're running 2, 3 today. So that’s had an impact as well. And there is virtually very little weekend work now.
Got it. And then last one for me I think a while back, you guys have broken down the working versus idle units both with wireline and well service rigs. Can you update us where that stands today?
Yes in wire line we're marketing about 60, 65 units in well servicing. We're marketing kind of 90-ish, 85 to 90 units now. That’s a little burdensome there because a stack unit isn’t paying for labor other than the unit manager, but so then hurt you quite as much and in coil I would say, was probably in that six, seven unit range that we're actively marketing.
Okay. Thank you, gentlemen.
Alright. Thank you.
[Operator Instructions] And if there are no further questions, I’d like to turn the floor back over to Mr. Locke for any closing comments.
Alright, well thank you very much for asking the good questions and participating in the call and we will look forward to visiting in the next quarter and hopefully have more good news at that point. Thank you very much.
Ladies and gentlemen thank you for your participation. This does conclude today’s conference. You will find the reply instructions on this morning’s press release. You may disconnect your lines and have a wonderful day.
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