Daniel Jenkins – Vice President, Investor Relations Donald Gawick – President and Chief Executive Officer Michael Galvan – Interim Chief Financial Officer and Chief Administrative Officer Pat Bixenman – Chief Administrative Officer and President, Research & Technology

Jud Bailey – Wells Fargo James Wicklund – Credit Suisse Scott Gruber – Citigroup Tommy Moll – Stephens John Daniel – Simmons & Co

Thank you, operator. Good morning, everyone, and welcome to the C&J Energy Services earnings conference call to discuss our results for the first quarter of 2018.

With me today are Don Gawick, President and Chief Executive Officer; Mike Galvan, Interim Chief Financial Officer and Chief Accounting Officer and Pat Bixenman, Chief Administrative Officer and President of Research and Technology. We appreciate your participation.

Before we get started, I would like to direct your attention to the forward-looking statements disclaimer contained in the news release that we issued this morning and is currently posted in the Investor Relations section of the Company's website. In summary, the cautionary note states that information provided in the news release and on this conference call that speaks to the Company's expectations or predictions of the future are considered forward-looking statements intended to be covered by the safe harbor provisions under the federal securities laws.

Such forward-looking statements are subject to risks and uncertainties, many of which are beyond the Company's control, which could cause our actual results to differ materially from those expressed in or implied by these statements. We refer you to C&J's disclosures regarding risk factors and forward-looking statements in our filings with the SEC for a discussion of the known material factors that could cause our actual results to differ materially from those indicated or implied by such forward-looking statements.

We undertake no obligation to publicly update or revise any forward-looking statements for any reason, and these statements speak only as of the date they were made. Our comments today include non-GAAP financial measures.

Additional details and the reconciliation to the most directly comparable GAAP financial measures are included in our first quarter earnings press release. As a reminder, today's call is being webcast live and a replay will be available in the Investor Relations section of our website.

Please note that information related on this call speaks only as of today, May 3, 2018. So, any time sensitive information may no longer be accurate at the time of the replay.

With that said, I'd like to turn the call over to Don Gawick, President and Chief Executive Officer of C&J Energy Services.

Thanks Daniel. Good morning everyone.

Thank you for joining us today to discuss our results for the first quarter of 2018. We delivered another quarter of strong results, capitalizing on increasing customer demand in our core service lines and improve market pricing.

We grew revenue 12.5% and adjusted EBITDA by over 28% sequentially. Achieving five consecutive quarters of double digit revenue and adjusted EBITDA growth is a solid testament to our ability to execute and deliver on our operational and financial plans.

In our Completion Services segment, we benefited from a full quarter impact of our 14th horizontal frac fleet, which was deployed in December 2017. We experienced minimal weather delays in our fracturing business, and due to our dedicated procurement and logistics teams and sand contracts, we didn't experience any significant delays waiting on sand.

Even though we expect the sand market to remain tight, we believe our procurement and logistics teams will be able to prevent any material downtime due to sand in the near term. In the wireline and pumping business, even though we encountered some pockets of weather and sand delays while working with peer company frac fleets.

This business improved sequentially in both revenue and adjusted EBITDA and generated greater margins than our fracturing business. We are confident in the strength of performance of our Completion businesses, and their ability to further improve.

First quarter results from our cementing business benefited from a full quarter impact of O-Tex's operations. We acquired O-Tex in November of last year and integration has proceeded according to plan.

Operating out of our new facility in Pecos, Texas, we are activating more equipment and investing in infrastructure to support more long string work as we seek to grow market share in Delaware Basin. I our coiled tubing business, we increased both utilization and pricing on our large diameter units in the quarter.

We expect to deploy two newbuild 2-5/8th inch units to dedicated customers at leading edge pricing upon delivery during the second quarter. We exit our directional drilling business in Q1.

It has not been meeting our profit margin targets. We are proud to deliver another quarter of significant improvement in our Well Support Services segment.

Revenue and profitability increased sequentially after adjusting for the sale of our Canadian rig service business in early November 2017. Despite weather delays in several operating basins, we experienced improved activity levels and higher pricing for our rig services.

In our fluids management business, we experienced improvement in both revenue and profitability due to improving activity levels and higher pricing primarily in West Texas. We exited the condensate hauling business in South Texas during the quarter, in line with our returns focused strategy of discontinuing businesses that do not meet our criteria for return on investment.

During the quarter, we began marketing our artificial lift business which is part of our Well Support Services segment. We expect the performance of our Well Support Services segment to further improve as a result of captured price increase.

We continuously evaluate our growth investments compared to our cost of capital to assure our plans generate the best possible return to our shareholders. The returns we generated with the capital we invested last year and the cash flow we are currently generating from our operations this year, keeps us convinced that our best option for driving shareholder value is to execute the growth plan that we announced earlier this year.

We will continue to monitor market conditions and retain the ability to adjust our growth plan to assure that we continue to achieve returns that meet our threshold criteria. The equipment deployed to-date has less than an 18-month payback.

We will also focus our capital on our most profitable businesses to reduce operating cost and lower overall SG&A as a percent of revenue. As we move into 2019 and are able to generated substantial free cash flow, we will evaluate all capital investment options and make capital spending decisions that generate the best return on capital possible, which could include some mechanisms to return capital to shareholders.

With that, I will turn the call over to Pat to discuss asset reactivation and progress on certain R&T initiative.

Thanks Don. In line with our growth plan, we deployed a horizontal frac fleet in the latter part of the quarter, which brings our active horsepower to approximately 655,000 hydraulic horsepower consisting of 15 horizontal and two large vertical frac fleets.

The majority of refurbishment CapEx in the first quarter was spent on our fracturing business, which included the ancillary equipment for the fleet we just deployed and initial spending on the three fleets we plan to deploy starting in May through July. We continue to experience numerous cost control benefits by using our San Angelo maintenance facility to manage our fleet refurbishment program.

Our growth projects and our wireline pumping and cementing businesses are progressing as planned. During the first quarter, we deployed four additional pumping units into service.

In our wireline business, we upgraded our service capabilities with advanced pressure control equipment and brakeless cable systems. In our cementing business, we've been successful in executing challenging long-string jobs and we're adding additional bulk equipment to increase the number of crews capable of running these challenging cementing jobs.

We're excited to start commercial jobs later in the second quarter with our new game-changer perforating gun developed and manufactured by our R&T facility in Houston, Texas. The game-changer gun is a port-less modular disposable gun system that uses our proprietary addressable switch.

We expect this gun system will reduce miss runs by up to 60% by eliminating the problems associated with loading and arming conventional guns at the well site. In addition to superior arming and loading features, this system is shorter than conventional guns making it easier to handle at the well site, as the number of guns run in a single stage continues to increase.

We will have additional manufacturing capacity operational by the end of the second quarter to increase our perforating gun production which will drive further cost savings and allow us to supply the majority of our wireline gun requirements. We're starting to install our warm start system for our frac pumps using our proprietary MDT frac controls.

Frac pumps are typically less idling between stages due to the difficulties in restarting them using the tractor hydraulics. Our warm start system does not rely on the tractors to start the pumps.

Rather we can shut down the pump from the data van after each stage is completed and then restart them prior to the next stage from the pump control system and the data van. Once fully deployed, this system is expected to reduce our fuel expense for fracturing by approximately 10%.

With that, I will turn the call over to Mike to review our first quarter financials.

Thanks Pat. Starting with our consolidated results, we grew revenue 12.5% to $553 million compared to $491.8 million in the prior quarter.

We generated net income of $20.6 million in the quarter, or $0.31 per diluted share and on an adjusted basis, net income totaled $27.5 million or $0.41 per diluted share after taking into account certain non-routine items detailed in our earnings press release. In the prior quarter, adjusted net income totaled $19.7 million or $0.31 per diluted share.

For the first quarter adjusted EBITDA totaled $73.7 million, a 28.7% increase compared to $57.3 million in the prior period, which generated 13.3% adjusted EBITDA margin and 27% incremental margin in the quarter. Now turning to the business segments.

We grew Completion Services revenue 9% to $374.1 million compared to revenue of $343.2 million in the prior period. First quarter adjusted EBITDA increased 11% to $80.9 million compared to $72.6 million in the prior period, which generated 22% adjusted EBITDA margin and 27% incremental margin for the segment.

Within our Completion Services segment, fracturing revenue increased just over 9% to $269.5 million compared to $246.8 million in the prior period, which resulted in an adjusted EBITDA margin in line with the segment margin. During the first quarter, we established our new Well Construction and Intervention Services segment which includes the results from our cementing and coiled tubing service lines.

The sequential improvement in this segment was primarily driven by the full quarterly impact of the O-Tex acquisition that closed on November 30, 2017 and improvement of both utilization and market pricing in our coiled tubing business. Revenue for this segment increased 55.3% to $87.4 million compared to revenue of $56.3 million in the prior period, and even with the exclusion of the O-Tex results, the sequential revenue increase was still in the double digits at 10.7%.

First quarter adjusted EBITDA increased 64% to $16 million compared to $9.8 million in the prior period, generating an 18% adjusted EBITDA margin in the segment. We were pleased to deliver another quarter of improved financial performance in our Well Support Services segment by further streamlining cost and increasing pricing based on improving customer demand.

Revenue declined slightly to $91.4 million compared to revenue of $92.3 million in the prior quarter, which was due to a loss of revenue from the sale of our Canadian rig services business in early November of 2017. First quarter adjusted EBITDA increased 89% to $5.1 million from $2.7 million in the prior quarter.

In line with Don's earlier comments, the sale of our Canadian rig services business is an example of our returns focused strategy of discontinuing underperforming businesses and we're confident keeping the focus on performing assets will improve the financial performance of this segment in the coming quarter. Moving on to expenses.

SG&A and expense in the first quarter was $65.9 million compared to $68 million in the prior quarter. The sequential decrease was mostly driven by fourth quarter expenses related to restructuring and severance cost associated with the sale of our Canadian Rig services business as well as integration and transaction cost associated with the O-Tex acquisition, all of which were offset by severance and accelerated equity vesting associated with the departure of an executive officer in the first quarter.

Excluding these non-routine type costs, adjusted SG&A as a percentage of revenue decreased from 12.1% to 10.8% or 130 basis points due to operating leverage generated from higher revenues. Looking ahead to the second quarter, we expect SG&A expense to further decrease and range between $61 million and $65 million.

Depreciation and amortization expenses totaled $46.3 million in the first quarter compared to $39.9 million in the fourth quarter. The sequential increase was driven by increased capital expenditures as well as the integration of the O-Tex asset base for the entire quarter.

Looking ahead to the second quarter, we expect depreciation and amortization expense to increase consistent with our capital expenditure program and range between $49 million and $54 million. And moving on from a tax perspective, we're in a great position.

We expect that we will not be a cash tax payer in 2018 and 2019 and for a few years after that, outside of nominal state and local taxes. We have approximately $1.1 billion of NOL value from prior years and repurchase premium associated with our emergence from Chapter 11 that we expect to utilize over the coming years to offset positive earnings and provide significant incremental free cash flow.

Now, to put this into perspective, using a 21% effective tax rate, the value of our NOLs will generate approximately $230 million of incremental free cash flow and when it comes to capital deployment strategy, accelerating to release that this value plays a significant role in our investment decisions, since any capital deployed to income generating assets this year and in the coming years will essentially provide tax returns on investment until the NOLs are fully utilized, which increases the return on capital deployed. Now looking at cash flow, we generated $35.7 million of cash from operations during the first quarter which was primarily driven by our improved financial performance and our focus on improving our net working capital position.

As we exclude operating cash out flows related to prior year activities including the tax settlement associated with our emergence from the Chapter 11 restructuring, cash flow from operations would have been a little over $70 million at quarter end. Capital expenditures totaled $63 million in the first quarter, compared to $58.7 million in the prior period.

As Don previously mentioned, market conditions and customer demand remained strong and we believe investing capital back into our businesses will generate returns that significant exceed other capital deployment options. Growth capital deployed only after a through returns analysis that includes a required return on investment well in excess of cost of capital and targeted payback periods generally less than 18 months.

In our fracturing business, we've generated payback periods of less than one year on capital deployed into our frac fleet in 2017 and we currently expect payback period of generally less than 18 months in 2018. In our wireline and pumping business, we generated payback periods of slightly less than one year on capital deployed in 2017 and we currently expect even shorter payback periods in 2018.

Similarly, in our coiled tubing business, we are targeting payback periods of less than one year on our growth plan. Now turning to liquidity in the balance sheet, as of the end of the first quarter we had a cash balance of $88 million and no outstanding borrowings on our credit facility.

We're pleased to announce that on May 1, we entered into a new $400 million asset based lending facility that more than doubles the size of our previous credit facility, brings the financial terms and covenants in line with market and extends the maturity date to May of 2023. We do not anticipate needing the extra borrowing capacity in the near term, but our new facility provides us with the financial flexibility to execute our returns focused strategy for the coming years.

As of the end of the first quarter, under the new facility and on a pro-forma basis, we would have $325.5 million of borrowing capacity available, resulting in total liquidity of $413.5 million. We are very pleased with the outcome and the added financial flexibility the new facility provides.

With that, I will turn the call back over to Don for a few closing comments.

Thanks Mike. I'm very proud of how our team executed during the first quarter, which resulted in improved revenue and adjusted EBITDA relevant to the market.

As I stated earlier, customer demand remained strong. We believe that our invested return on capital involves some vesting in our businesses to execute on our current wealth initiatives.

Regionally, the U.S. onshore rig count exceeded 1,000 rigs and the U.S.

onshore permitting activity is off to a strong start compared to 2017 levels, which along with the strong oil price bodes well for increased completion activity in the near-term. In 2017, our growth initiative generated attractive returns with our capital investments in many of our businesses generating paybacks of less than one year.

The market remains strong and we believe that improved customer demand and higher market pricing compared to 2017 levels should drive strong returns and paybacks for our 2018 capital spending projects. We will continue to monitor and analyze the best returns for the use of our capital and will adjust as the situation evolves.

Our decision to stay true to our core philosophy of divesting businesses or assets that don't meet our return threshold should result in lower cost and improved returns. Finally, I want to thank our employees for their continued hard work and dedication.

We have an incredible group of talented and passionate people committed to making our company the very best in the oilfield services industry. Thanks again for joining us on our call today.

And we appreciate your interest in C&J. Operator, we're now ready to open the call to questions.

Thanks. Good morning.

First question is on, you guys – the impact of shutting down directional lift, it looks like that's probably helping G&A in the second quarter some. I was wondering if you could help us think about over the next maybe two or three quarters, as you embark on trying to cut G&A more, and the impact of shutting these businesses down.

Do we see the full impact in the second quarter with that guidance of – I think it was $60 million to $65 million, or is there potentially more downward pressure as we get into the back half of the year or do we see it all upfront?

Yeah, sure Jud, this is Mike. I think the way to look at it is, the current range we provided, I mean we were definitely with the growing business, we're going to stick to maintain that level and the focus here is going to be just generating some meaningful and significant operating leverage as we proceed through the year.

So, yeah, from those divestitures of those businesses, you can definitely see the range has gone down, especially from the last quarter's range that was provided. That's some of it, some to do with it.

But again, I think the current ranges that we're providing for the second quarter guidance, I think, there is $61 million to $65 million. That's definitely going to be – we will foresee that, being a reasonable range going forward for future quarters.

Okay, alright, thank you for that. And then my second question maybe for Don.

Could you – you gave good clarity on the next two deployments for your frac fleets. Can you talk about your visibility or conversations you are having and how you are thinking about any potential deployment for the second half of the year?

I know previously you had indicated, you'd expect to deploy the remaining fleets, but I wonder if you could give us an update, give thoughts on the dynamics going on the market today.

Yeah. So, we are continuously reviewing those.

As we say, we've got plans right now to deploy three more fleets that we previously announced. We've got three fleets left after that.

I'm looking at what's available in the market. We're getting lots of demand, lots of inquires about putting fleets out and we're still using the same criteria we've used since we come back out of the Chapter 11 and that's the – we really need to see that we've got a customer who can get us fully utilized and working essentially in a factory in a 24/7 type mode.

But it's a long list of potential targets that we can be drilling, so it's a year plus type of commitment and we do want to see the kind of margins that really need to sort of a payback period on what would be a new build cost of somewhere around two years. We haven't altered our criteria at all.

At this point, we are not getting that level of profitability or duration or full utilization that we're seeing in terms of the commitment from customers. So, one of the last three, we have gotten that, but two of the last three, we have not at this point, so we've not pulled the trigger on deploying the last couple of fleets yet.

We'll keep looking. Our expectation is at some point we'll get those criteria met, but that has not happened at this point.

Okay, and if I could follow-on to that. And thank you for the color.

If you don't deploy those last two, let's just say, you only do the one of the last three. The previous CapEx guidance $430 million to $450 million, I assume that would come down if you don't deploy those last two.

Just want to confirm them?

That's correct. So, the $430 million to $450 million, had all of the fleets being deployed.

And basically for the last – if the last two were not to be deployed, you can take just a little under $60 million out of the CapEx projection.

Got it. Thank you.

I'll turn it back.

Thank you.

Good morning guys. Little bit of a follow-up if I could.

I mean your return focus which we all loved to hear, believe me. And you talk about how the pay back on some of these incremental things you are doing are less than a year.

With those kinds of returns, how do you reasonably gate your capital allocation? Is it strictly term at this point and are there returns that you are getting, that you mentioned sub-one year today, are those just on shorter-terms that stops you from committing additional capital?

Can you talk about that? The biggest fear in the market of course is that, everybody in the frac business is going to dramatically overbuild capacity any time soon, and when we hear, sub one-year returns that kind of makes us think that you know, the wheel is going to go nuts any minute now.

So I'm just curious to what you have to see before you start expanding capacity on those kind of returns and is it in particular business lines or is it just incremental things you are adding?

Yeah. Good question Jim.

So, I want to be really clear. The sub-one year returns is not in frac at all.

That's – it's absolutely not in frac. Really I want to emphasize again, we've got a lot of product lines other than frac.

We're very broad in the Completion space.

That's why we like you.

Yeah. And the sub-one year returns are in other product lines and you are deploying those essentially, quite frankly, the bottleneck there is people.

We're crewing up and putting that equipment to work in those product lines, we are expanding as we can hire, train and deploy the equipment and the new employees. So – but it's certainly not in frac.

Perfect. That's good to hear.

And you segued into my follow-up. In the couple of years I've been doing this, we've always complained or mentioned people – hiring people as one of the concerns, but we've really never lost a dollar of revenue, because we couldn't hire people.

And it seems that this cycle or this year that may actually be the case. Can you talk about what do we do for people, especially in places like the Permian and just paying people more, just moves people around.

It doesn't solve the problem. Do you think we'll actually miss a dollar or two or revenues this year, because of shortage of people?

And what do we do about it?

I really do think we'll miss some top-line, because of the shortage of people. And quite frankly, we're having to address the issue on a number of – in a number of different ways.

And you are right, just you are paying a little bit more money here and there, quite frankly, still keeps people moving around, because everyone is looking to get the people out there or even looking to poach from other product lines. We've certainly seen some of that and you do have to react with how your wage is.

But what we've done is really beefed up our recruiting efforts significantly. We're doing a lot of recruiting around the country and quite frankly having some good success of getting people to sign on in sort of non-traditional oil areas if you will.

We're focusing a lot in various job fairs and having some good success. That means rotating people, so giving them very good time on and time off schedules.

It means giving them some good housing and a place that they feel good about living in while they are on duty in basin and fast forwarding the folks in and out of there. So, there are some costs associated with that obviously, but clearly you've got to do that just to get staffed up and get more equipment deployed into the field.

And quite frankly the retention issue really requires that you take a look at some of the soft issues with your people. You know it's not just about the money certainly.

Great clarification. Thank you very much.

Appreciate it.

Thank you.

Good morning, gentlemen.

Good morning.

Look, I appreciate that you are reevaluating you deployment schedule here in frac in the second half. It seems like a very prudent strategy here.

But I just wanted to get your thoughts kind of in general. You know, the investment community is nervous with regards to the new frac capacity coming into the market.

And I think the – a lot of the concerns stems from the common industry practice of ordering capacity on a speculative basis. How do you think about that practice and it should be the industry really shifts towards demanding contracts with some teeth, when deploying growth capital at this point in the cycle?

It would be great if we could see that kind of environment exist and something similar to what you're seeing on the drilling side of the business, where you know, quite frankly you've got a contract in place and rates are specified, the duration specified. You know, in all honesty aside from drilling the U.S.

land business with the exception of the boom that we say from 2010 through the first part of 2014, the notion and firm contrast in the other traditional completion oilfield service businesses has never existed. I think the incredible undersupply that we had at that time was the only reason that could happen.

And quite frankly, I think for a lot of companies that had what we referred to as take-or-pay contracts, most of those ended quite badly. I don't know that there is a lot of interest – most people in terms of the true take or pay type environment.

I think we're going to see more people, more of our customers in fact they are asking to make some commitments and we set up a flexible schedule with respect to be able to pass through some of the – rather all is what we want of the increases in the class to us and the ability to revisit the pricing on a regular basis, so that we're not left with any increases in labor or commodities or some of the fixed variable expenses rather that we see. So, we certainly look for a commitment from the customer that you know they are going to meet our three criteria.

Again if they choose to go to another direction, but the current agreements that we have, they can do that. So, it's incumbent upon us to make sure that our execution and our service delivery lives up to the expectations that they have.

And again, we expect to continue to pass through price increases and move the market as we see the overall activity continue to improve. So, we are very, very careful to make sure that we meet those criteria.

And if we don't see them, then we're not going to deploy. But again, they are not fixed locked-in contracts as you said.

That it would be a – a much easier environment to operate in if that was the case, but unfortunately that's not the market that we're in.

Why do you think the contracts held on the drilling side even through the downturn but didn't hold on the frac side?

Well, I think the contracts, in fact most of the frac side contracts did hold, but we saw such an incredible older build in that particular cycle and such and overshoot, that's called the [PE center], all of the regular, the public companies increased their capacity as well, that there was a real drop in the overall rates. As we came out of 2014, and frac companies that held the line on those contracts, quite frankly the day they ended, they were cut off and essentially no longer providing services to the market.

So, I'd say in general, the frac service companies got probably a little bit greedy, weren't really particularly flexible and the incredible swing from very, very undersupplied to suddenly very oversupplied left the E&Ps feeling that somewhat taken advantage of and again that's the only time in my career which goes back in late 1970s that we've had an environment like that and I don't think it's one we'll see return and I'm not sure again that the E&Ps would necessarily want to see it.

I can actually count up on a 15 million to 16 million horsepower in hands of companies with scale today. Do you think that would start to change this behavior?

I mean are we – could we actually be at an inflection point where we see some better behavior given that the vast majority of the industry 85% to 90% is of the capacity is in the hands of companies with scale now.

Yeah, I think in general what I'm hearing and from our peers and I know certainly something that we've been fixed on doing for the entire up-cycle here is, just evaluating how firm the commitments are what the markets looks like. I do think there is a little bit more disciplined coming into the market, certainly more than there was back in that, 2011, 2012 time frame.

Got it. Appreciate the color.

Thank you.

Thank you.

Good morning. Thanks for taking my question

Good morning.

So, I wanted to start on sand. You mentioned that you really didn't encounter as many logistical challenges there as some others did.

Could you share how you were able to navigate around the rail disruptions?

Yeah sure. We were fortunate to have sand contracts for both northern and region.

And we have enough suppliers where we could. When we hit those pinch points, we could move the supply to another supplier that we're able to backfill.

But – our procurement logistics team worked very hard and we're very proactive in looking at potential shortfalls and jumped on as early as they could.

So there wasn't any margin impact there what you just described?

I would say there was a little bit, but quite frankly and again just going back a number of years, there are disruptions in Q1, and that's a very normal thing to have happened. You have severe weather.

You've got times where you've got very heavy snow. You've got various parts of the country where you got issues that just caused delays, and so but we saw that our frac business was – what I'd characterize as kind of typical Q1 delays and issues.

But they weren't unusual. So, they do have an impact.

If everything is done without any of those delays, we certainly would have seen higher top-line and higher margins as well. But they weren't unusual, and so I think there is a couple of factors there, one is, like Pat said, we've got a mix of supply available to us.

On the sand side, we've got a very good relationship with our suppliers and logistics team did a great job of staying on top of that. The other issue I think as well is we don't have a lot of our frac horsepower deployed in the north, where quite frankly I think some of those issues were somewhat – and as a result we didn't have issues getting the few frac fleets we have in the northern part of the country supplied with sand.

Another issue we've got is that, we're seeing an increase in the amount of sand that's being supplied by the E&Ps themselves and that percentage continues to go up. The people we're working with have very good logistic operations as well and they were on top of getting the sands to their locations in a timely manner.

So, that certainly did help with the cause. One thing that we saw, because we have very large wireline fleet, we do tend to do the plug and perf for a lot of our peers, so we're on a number of locations where they are doing the frac work and we did see in February, probably a week to 10 days, a number of frac companies where we were providing the pump down wireline work, sitting and waiting on delay.

So, we know there were some real issues with some of our peers in various part of the country, but again we were able to avoid those. The few weather delays we had quite frankly, were mostly associated with our work over rig business where if you get very high wins, you simply can stand the rigs up and work.

We saw quite a bit of that in the Rockies this year and actually a little bit in the Mid-con and even West Texas some days where it was very windy. And we've also got a very large presence in California with both the trucking business there and the work over rig business.

And quite frankly, we were impacted a number of days in both of those in California, because in one case it was the fires, and in other case it was very, very heavy rains. But again, we don't frac in California, so that – now impact on that part of the business.

Great. Thanks.

And then just shifting to the macro, I wanted to talk about attribution of the frac fleet, not your specifically, but just high-level here. It's a theme in the Lower 48, that gets a lot of attention, but it's hard to put numbers to it.

Some of your peers in recent weeks have said that it could be as much as half of the newbuilds that have been announced. They are actually just going to replace existing equipment versus to add new fleets.

How do you all think about that and if you look at where we sit in terms of demand versus supply today, do you think we get – how do you think that evolves through the rest of the year?

Yeah, and you are right, it is a hard number to put – to get your hands on quite frankly. And it's something I think that varies pretty dramatically depending on which services company you are talking about.

Certainly, there are a number of new firms coming into the marketplace that are adding horsepower where all of it is in addition of the market. They are coming out with either rebuilt pumps or they are coming up with new equipment.

And so that part of it is going to be pure add. The guys that have been around a long time and especially folks that have got some pumps that continuing to work, fleets are continuing to work through the down cycle and so by definition, they've got units out there that are approaching you know that 8, 9, 10-year life.

Those are the ones that you are going to see – continue to have to actually retire that equipment, because it's gone through probably a couple of rebuild cycles. And the economics and expected life coming out of another rebuild just simply doesn't justify it.

So, in my mind, the attrition issue is real. I know I saw a peer the other day saying, the equipment doesn't go away.

That's simply not true in frac. The equipment actually – absolutely does go away after a couple of rebuilds.

And one of the things we look at is, typically getting two rebuilds, refurbishments out of fleet after the initial three or four years that it's working. So, sort of in an 8 to 10 to 12 year cycle before that fleet is really – it's just not worth to be rebuilding again.

So, if you look at that on sort of an ongoing basis, that suggest somewhere around a 10% attrition rate if you average it out in a normal cycle. Given that we've got some much old horsepower though in the market, I think the attrition is certainly higher than that.

50% strikes me, personally is a little on the high-side quite frankly, but I think somewhere in between that sort of traditional 10% to 12% number and 50% is probably closer to the truth.

Great. Thank you.

I'll turn it back.

Thank you.

Hey thanks for taking the call – the question.

Hey, John.

You guys have previously discussed a few of the strategic review of our Well Service Business. I'm just curious if you can update us on where this process stands?

Yeah. It's – we continue to do that and really we're looking at, you know few different options.

We've been talking with a number of different people. We've actually gotten a little bit of an increase in interest with some enquires coming in from a few players, a bunch of potential opportunities there.

At this point, all I can really say is we're continuing on discussions, we're looking at the options, we want to make sure, it makes sense in terms of valuation and puts us in a situation that we feel would be advantageous. One thing I'll really stress is that, while we're doing that, we've been executing very aggressively on our plan to get that business back to some reasonably – reasonable EBITDA margins.

And if you take just the Well Servicing business itself, which specifically is talking about the rig business and the fluids business, our margins are coming up nicely. We actually exited Q1 at just the low double digit EBITDA margins.

And our expectation again is to be solidly in the double digit for the year. They continue to improve and quite frankly April is looking better than the exit was from March.

So, we've passed on some fairly aggressive price increase. And especially in trucking and as well as on the rig side.

And we're moving in the right direction. And in fact the improvement in profitability in that business is ahead of plan.

So, even if we don't find a deal that makes sense for us, it's going to be a portion of our business. But quite frankly continues to shrink as a percentage of the total, but it's going to be a nice contributor to the bottom-line.

And again, when the next down cycle comes for completion and we know one will, there is going to be a day when we say, you know well it's pretty good to be in the work over rig and trucking business. So, we're not looking at exit at all cost, scenario whatsoever.

It's really got to be one that does make sense for us and if a deal isn't imminent then we'll just continue to get to bottom-line better and better in that business.

I've got a more of a high level question for you here now. As you look towards the back half of the year, I think today the Permian differentials are I think at $12 a barrel, so they seem to be widening.

I'm just curious like, what type of contingency plans you guys might be building in if customers slow down, or if you see any of the signs of that that and if I was your customer, I would certainly come back to the service and ask for a price relief just given the differential. Have you seen that yet and do you expect to see that?

We're certainly not seeing it at this point. You know we have seen I would say in the Permian marketplace, certainly a bit of softening on these spot pricing.

Again because of the actions of some specific players that are coming and trying to put some newly deployed equipment to work. So, they are willing to go into somewhat lower rates.

But overall, the feedback we're getting from our customers and the – especially on the dedicated crews, I mean we're continuing to be busy. We've actually getting more requests for more dedicated crews, especially with some people we already have fleets out for where they want more – another fleet from us.

And so there is nothing showing up yet in terms of the customer reaction or any of the language we're getting from them. I do think that's something we have to keep a very close eye on as an industry.

And again, if you are depending on how the market moves are going forward, the differentials gets high enough, certainly at some point that's going to be reflected in the activity and eventually reflected in the price levels we can get. So, again not seeing it today, but it's certainly a trend we're paying a lot of attention to.

Okay. Cool.

And just one last housekeeping from me, and I'm assuming the answer will be yes, but is it safe to assume that you guys won't order new frac fleets until the remaining three idle fleets are deployed?

Yeah. That's absolutely the case.

I can say at this point we have no plans to order any new frac fleet beyond what we currently have for available horsepower.

Thank you very much for your time.

Thank you.

Thank you operator and thanks to everyone who called in today. We appreciate your interest in C&J and look forward to speaking with you again on the Q2 call.

Thank you.