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Patterson-UTI Energy Inc
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Ladies and gentlemen, thank you for standing by, and welcome to Patterson-UTI Energy Third Quarter 2019 Earnings Conference Call. [Operator Instructions].
I would now like to hand the conference over to your speaker today, Mike Drickamer, Vice President Investor Relations. Thank you, please go ahead.
Thank you, Mariama. Good morning, and on behalf of Patterson-UTI Energy, I'd like to welcome you to today' conference call to discuss the results of the 3 and 9 months ended September 30, 2019.
Participating in today's call will be Mark Siegel, Executive Chairman; Andy Hendricks, Chief Executive Officer; and Andy Smith, Chief Financial Officer. A quick reminder that statements made in this conference call that state the company's or management's plans, intentions, beliefs, expectations or predictions for the future are forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995, the Securities Act of 1933 and the Securities Exchange Act of 1934. These forward-looking statements are subject to risks and uncertainties as disclosed in the company's Annual Report and on Form 10-K and other filings with the SEC.
These risks and uncertainties could cause the company's actual results to differ materially from suggested in such forward-looking statements or what the company expects. The company undertakes no obligation to publicly update or revise any forward-looking statement. The company's SEC filings may be obtained by contacting the company or the SEC and are available through the company's website and through the SEC's EDGAR system. Statements made in this conference call include non-GAAP financial measures. The required reconciliations to GAAP financial measures are included on our website, www.patenergy.com, and in the company's press release issued prior to this conference call.
And now it's my pleasure to turn the call over to Mark Siegel for some opening remarks. Mark?
Thanks, Mike. Good morning, and welcome to Patterson-UTI's conference call for the third quarter of 2019. We are pleased that you can join us today. This morning, I will turn the call over to Andy Smith, who will review the financial results for the quarter ended September 30. He will then turn the call over to Andy Hendricks, who will share some comments on our operational highlights as well as our outlook. After Andy's comments, I will provide some closing remarks before turning the call over to questions. Andy?
Thanks, Mark, and good morning. As set forth in our earnings press release issued this morning, for the third quarter, we reported a net loss of $262 million or $1.31 per share, which included charges totaling $260 million pretax or $209 million after tax. Excluding these charges, the net loss for the third quarter would have been $52.9 million or $0.27 per share.
I'd like to provide some additional information to help you better understand these charges. They're primarily driven by the current market environment and, in particular, the fact that we do not have visibility to a major upturn in the near term. Included in our depreciation, depletion, amortization and impairment expense, is a $203 million noncash impairment charge, including $173 million in drilling, $20.5 million in pressure pumping, $8.4 million in directional drilling and approximately $0.5 million in our other segment. These impairment charges include the retirement of 36 legacy non-APEX drilling rigs for which there is limited perceivable opportunity to work at rates and terms, which would justify the activation of the rigs. Additionally, included in the impairment charge is the retirement of approximately 300,000 pressure pumping horsepower.
During the third quarter, we took a $17.8 million noncash goodwill impairment charge related to all of the goodwill remaining in our Current Power and Great Plains Oilfield Rental businesses. The profitability and resulting cash flow of these businesses is highly correlated to overall oilfield service activity. And as such, I felt the effect of the latest downturn. Included in the direct operating cost of our directional drilling segment is a $17 million -- a $17 million for the write-off of inventory.
Included in the direct operating cost for our Warrior Rig Technologies business, which is in our other segment, is $12.4 million, primarily related to the write-off inventory for product lines we no longer intend to support. These product lines generally included hydraulic top drive and first generation electric top drives.
Additionally, $2.2 million of severance expense is included in SG&A for our other segment, as we have ceased operations in our Calgary locations. Included interest expense is an $8.2 million -- is an $8.2 million make-whole charge incurred in connection with the early repayment of our $30 million Series A senior notes due 2020. Excluding these charges, the majority of which were noncash, our adjusted EBITDA for the third quarter would have been $143 million.
During the third quarter, capital expenditures totaled $68 million, a 30% reduction from the second quarter. We now expect full year 2019 CapEx to be approximately $350 million, down from our expectation last quarter of $400 million and down from our original budget for the year of $465 million, as we have quickly reacted to market conditions to reduce spending. During the third quarter, we reduced our gross debt and pushed our nearest debt maturity to 2022 by using a combination of cash and a new $150 million term loan to repay a $300 million tranche of senior notes that would have been due in 2020.
The new $150 million term loan has current pricing of LIBOR plus 108, which is currently 2.95% and gives us the ability to continue to reduce debt without prepayment penalty. Our liquidity position remain strong with $165 million of cash on the balance sheet at the end of the quarter, and $600 million available under our undrawn revolving line of credit, which matures in 2024.
At September 30, 2019, our outstanding gross debt balance was $975 million, a $150 million reduction from the end of the prior quarter. Our net debt-to-capital ratio was 21.6% at September 30, 2019. During the third quarter, we repurchased 8.2 million shares of our common stock in the open market for $75 million. Through the first 3 quarters of 2019, we repurchased a total of 20 million shares in the open market or 9.4% of the shares outstanding at the beginning of the year at an aggregate cost of $225 million. Our remaining share repurchase authorization is $175 million.
In addition to the share repurchases, we also paid $7.8 million in dividends during the quarter, and have paid $24.7 million through the first 3 quarters of this year.
Turning to the fourth quarter, we expect depreciation, depletion, amortization and impairment expense to be $188 million, SG&A to be $31 million and our effective tax rate to be approximately 20%.
With that, I'll now turn the call over to Andy Hendricks.
Thanks, Andy. Before we get into our third quarter results, I wanted to give everyone an overview of what we're seeing in the market. It's been a challenging year with the overall decrease in U.S. industry rig count, and the third quarter was the quarter with the fastest decline during the year. For Patterson-UTI, the decrease in our rig count was in line with our expectation, while the decrease in pressure pumping activity was greater than we expected.
With WTI in the low to mid-50s, operator activity continues to be motivated by staying within budget and therefore, operators that outspend their budget in the first half of the year, are slowing activity in the back half of the year. Both drilling and pressure pumping activity are expected to decline further in the fourth quarter, but recent customer conversations suggested our drilling rig activity will bottom in the fourth quarter and then a modest increase in late December and early January.
At this point, there is limited visibility to how 2020 activity will shape up, and we will know more later in the year as operators work on their budgets. As I visit with customers, the way many of them describe their drilling and completion programs going forward is steady. And at Patterson-UTI, we are adjusting our business accordingly.
In contract drilling, our rig count during the third quarter averaged 142 rigs, in line with our expectations. Average rig revenue per day for the third quarter increased to $24,240 from $24,200 in the second quarter. The third quarter had a lot of cross currents that affected average daily revenue, including higher-than-expected early termination revenue; an increased proportion of rigs on standby, which is dilutive to the average and improving rig mix and some pressure on leading-edge dayrates.
When excluding the impact from rigs on standby and early terminations from both the second and third quarters, average daily revenue increased $160 sequentially in the third quarter due primarily to a more favorable rig mix.
Average rig operating cost per day during the third quarter increased to $14,440, due primarily to lower fixed cost absorption related to the steep drop in the rig count during the third quarter as well as increases in items, such as workers' comp. and medical insurance, which we assume will not recur in the fourth quarter. At September 30, we had term contracts for drilling rigs providing for approximately $645 million of future dayrate drilling revenue. Based on contracts currently in place, we expect an average of 73 rigs operating under term contracts during the fourth quarter and an average of 55 rigs operating under term contracts during the 12 months ending September 30, 2020.
We have retired 36 non-APEX rigs. Given current market conditions and our customer strong preference for super-spec rigs, we believe these rigs have limited commercial opportunity going forward. Our current rig fleet of 216 rigs includes 198 APEX rigs, of which we consider 150 to be super-spec.
Turning now to our contract drilling outlook. We expect our rig count to average 126 rigs in the fourth quarter, essentially in line with our current rig count. We expect that our rig count stabilizes near current levels and bottoms in the fourth quarter with some increase in the first quarter as operator budgets reset in 2020. Average rig revenue per day for the fourth quarter is expected to be $23,500. Approximately $280 per day of the decrease in the fourth quarter average revenue per day is related to an assume decrease in the early termination revenues.
With the expectation of rigs going back to work, we are going to have to carry some additional labor expense in the fourth quarter as we have employees ready to go to work when these rigs are reactivated.
Despite these higher labor cost, we expect our fourth quarter average rig operating cost per day to decrease approximately $200, as some of the items that affected the third quarter are not assume to repeat in the fourth quarter.
Turning now to pressure pumping. Gross margin of $32.3 million on revenues of $209 million was lower than we expected as activity fell more than expected during the quarter. We reduced our active spread count and ended the quarter with 14 active spreads. Activity continues to decrease, and we idled an additional spread early in the fourth quarter. Lower activity levels are negatively impacting pricing, such that we believe industry pricing for spot work is at an unsustainably low level.
With the reduced activity and increased white space in the calendar for active spreads, we expect fourth quarter pressure pumping margin to be approximately $8 million with revenues of approximately $150 million. We have been and continue to reduce operating locations in order to scale the business for current market conditions.
We're seeing an increase in the number of operating operators looking for frac spreads in early 2020, but it is unclear whether this work will materialize and if the pricing on the work would be economic. We will continue to evaluate the economics of working versus idling spreads on a spread-by-spread basis. The pressure pumping market is oversupplied, and it has been since the end of 2017. Improvements in completion efficiency have exacerbated the problem of all the additional horsepower added to the market over the past 2 years.
At Patterson-UTI, we remain capital disciplined and focused on things within our control. During the third quarter, we undertook a thorough process to evaluate the economic opportunity for our fleet and decided to permanently retire 300,000 horsepower of pressure pumping equipment. We concluded that in the current market, the cost to reactivated this equipment would be prohibitive and with oversupplied market conditions, the best course of action would be to rationalize this equipment. Any components from this equipment with a remaining value will be used as parts to support our active equipment.
We believe this equipment rationalization will optimize our fleet in a manner that is capital efficient. More importantly, we believe that equipment rationalization provides a path to improving utilization in returns for the entire industry. Our remaining fleet of 1.3 million frac horsepower is more than capable of undertaking today's most challenging completion jobs in an efficient manner. We believe that the write-down and retirement of horsepower by a number of companies in the industry, along with the Q4 stabilization in the rig count and expected slight increase in the rig count in early 2020 is positive for pressure pumping market over the long term.
Turning now to directional drilling. Excluding $17 million of write-offs, third quarter gross margin was $7.8 million with revenues of $47 million. For the fourth quarter, we expect directional drilling revenues of $39 million with the gross profit margin of $8 million. Outside of unusual items, percent margin in this business has increased steadily over the last year.
Within our directional drilling segment, I would like to call out the success of Superior QC, our real-time data analytics and survey correction business. The market for survey correction has increased despite the falling rig count in 2019, as customer adoption of this technology has increased. This month, Superior QC surpassed a major milestone with remote data analytics services on more than 100 rigs.
Over the past year, Superior QC has provided survey correction for nearly 1,400 wells or more than 25 million feet of wellbore. The technology behind Superior QC survey correction software is being incorporated into our forthcoming bit guidance and drilling automation offerings. Leveraging this technology to help Patterson-UTI further differentiate itself from other peers without similar technology offerings.
Turning now to our other operations, which includes our rental technology and E&P businesses. In our Warrior Rig Technologies business, we made the decision during the third quarter to transition away from our engineering and manufacturing efforts in Calgary. This decision resulted in a $12.4 million charge in direct operating cost as well as a $2.2 million of severance expense in SG&A. Excluding these charges, the gross profit margin for our other operations during the third quarter were $6.4 million on revenues of $25.7 million. For the fourth quarter, we expect operational results similar to the third quarter.
With that, I will now turn the call back to Mark for his concluding remarks.
Thanks, Andy. Even in the down market our franchise remain strong, because of our high-quality rig fleet and operational expertise. In pressure pumping, we note that unsustainably low pricing levels are leading to horsepower attrition and industry participants, including ourselves, are retiring equipment. We believe this attrition will help correct the oversupplied market, which is currently leading to low-utilization levels.
That said, Patterson-UTI has a strong financial position, which has allowed us to focus on debt reduction and share buybacks. During the third quarter, we repurchased an additional 8.2 million shares. Since the beginning of 2018, we have repurchased more than 29 million shares or 13% of the shares outstanding at the end of 2017. Including dividends, we have returned more than $430 million of cash to shareholders since the beginning of 2018.
I would also like to call out that during the third quarter, we published our corporate sustainability report. I am proud of the initiatives we have pursued, some of which are highlighted in our report, which can be found in the Sustainability section of our website.
I'm also pleased to announce today the company declared a quarterly dividend -- quarterly cash dividend on its common stock of $0.04 per share to be paid on December 19, 2019, to holders of record on December 5, 2019.
With that said, we both would like to commend and thank the hard-working men and women who make up this company. We appreciate your continuing efforts. Operator, we'd now like to open the call for questions.
[Operator Instructions]. Your first question comes from Sean Meakim with JPMorgan.
Andy, could you maybe give us your take on your customers' expected actions in the first half of next year for both pumping and drilling activity? It seems to me they definitely use frac crews to moderate their spend as needed. But the rig count declines seems to indicated sustainably lower activity. I'm concerned that perhaps their shareholder base won't take too kindly upon rig additions earlier in the year even if maybe there's a little more flexibility around the frac crews. Just how do you think about those two dynamics given you guys are important competitors in both of those markets?
Yes. It's hard to know exactly what's going to happen throughout 2020 so far. Our customers are still, obviously, have ways to go before they work out their budgets for 2020. The most visibility we have at this point is what we've been discussing in that we've already been in discussions with operators who want to put rigs up towards the end of December and into early Q1. So we have some visibility on some increase in the rig activity into Q1. As we also mentioned, there are some customers that are looking at putting frac spreads out as well, but it's just not clear for us it makes economic sense. So I think there are still some moving pieces to go to fully understand this as we work through the rest of Q4, but we certainly don't have full visibility on 2020.
But we agree with you that over the last 2 years, operators have used all the completion services to moderate their budgets more than they have the rig count. But if we have the opportunity to put some rigs back to work under good terms, we're certainly going to take it towards the end of this year and early next year.
Right. I appreciate that. That's totally fair. And in the prepared comments, you noted the attrition obviously for your own fleet, but for a lot of your peers. So we are seeing that horsepower attrition, but it's not clear how much of that is the incremental horsepower, right? So maybe a lot of what's getting fenced is not necessarily going to be the first that will come off the fence if there is an improvement in activity. Could you maybe give us a sense of your confidence level with respect to supply-driven solution to the underutilization in the market heading into the next year?
Yes. In our particular case, the 300,000 horsepower that we're retiring will be gone. We may use some of the components of that. If some of the components on some of those -- whether it's pump systems or blenders have low hours, then we may use the components. But in essence, that horsepower and that equipment will be gone and won't return incomplete back to the market by any means. We'll continue to rationalize systems like that and I think others will do the same.
Our pressure pumping activity is going to slow down in the fourth quarter with more chunks of what I would consider white space in the calendar than we've seen in the past. And some of this has to do with seasonality, some of this has to do with budgets. We're going to retain some of the labor force there, because we may have an opportunity to put some of this equipment back to work early in Q1. And we'll just continue to monitor that as we work our way through the fourth quarter.
But in terms of -- I'd also like to point out CapEx spend will come down in the fourth quarter, because it's based on the maintenance CapEx on the equipment is based on the hours we put on the equipment. So we see that moderating in the fourth quarter as well on pressure pumping.
So I guess, just to put a finer point on it, do you think that the supply side can fix the underutilization? Or how much is really still relying on demand to help you get there?
I think that the supply side can and will fix the utilization. There is various industry reports about what utilization is today. Let's say it's in that 60% range, plus or minus, that's well below the 80% range that the industry needs to be healthy. And we haven't seen 80% since the end of 2017 in terms of industry utilization. And so the market has been challenged for a long period of time, but I think, with the retirements you're seeing from us and retirements of equipment you'll see from others and continued rationalization of equipment. I think, that the supply side will work this out. Now it doesn't happen overnight. It's not going to happen in a couple of quarters, but the supply side will work this out.
Your next question comes from Praveen Narra with Raymond James.
I guess, thinking about that kind of demarcation line on the 300,000 retirement. How do you think of the CapEx that was needed to be spent to bring that back to reactivate that? And what was considered too much?
Well, CapEx was certainly a consideration. The other consideration was just how much horsepower do we need going forward as a company and as an industry. And none of us need as much as horsepower as we own going forward, the market is just oversupplied. And there is no point in us trying to invest in all the horsepower that we have to keep it working. And so we just -- we had to find a point within our list of assets to draw a line and say, we just don't need this horsepower anymore, and we do that line at 300,000 based on our view of the market over the long term and our view of what it would take to invest in that horsepower.
Okay. Great. And I guess, maybe on the 4Q guide for pressure pumping. If I look at kind of the incremental or decremental margin guide, it's a bit higher than you guys have historically run. I guess you addressed it a bit on Sean's question. But how should we think about that willingness to hold on? And i know you're not giving 1Q guidance, which we -- should we assume that you're holding on because 1Q gets better and so incrementals are better on the other side. How do we think about that?
Yes. 1Q has the potential to be better than Q4, because some of the seasonality effects that we're going to see in Q4 along with some operator slowing down because of their budgets. And so the work gets rather blocky with chunks of white space in there, but we still need to hold the people as we work through the fourth quarter, that's important to us. We have good equipment. We have good people. And I'll reiterate as a company, we have a great balance sheet, and we're in this for the long term.
Okay. If I could squeeze one more and just on the working capital side. It looks like noncash working capital did really well in the third quarter. Can you talk about how you expect that to go into 4Q? And then any initiatives on if that can get a better from here or if it was just somewhat timing?
Yes. This is Andy. I think we've seen the bulk of the improvement in that. We may have a little bit more to go, but it's kind of depends on the market as 4Q is sort of a lower activity quarter. We may see a little bit more of that coming back to us and then as we rebound a little into 2020 see some of that come back off.
Your next question comes from Connor Lynagh with Morgan Stanley.
Just wondering if you could characterize the pricing environment in land drilling right now. It's certainly been a concern in a lot of people's minds. Maybe you don't want to give specific dayrates, but could you characterize contracts that you're signing work in December and early next year that are driving the increase in rig count. How do those compare to where the -- your realized rate is right now?
On the rig itself, there is some pressure on the leading-edge dayrates. We've been acknowledging that on the last couple of calls. It's natural that there's many rigs that have come down. But -- again, as I've said before, I don't think this should be a panic when we talk about a little bit of pressure on dayrates on rigs. This is a market that has shown very good discipline in terms of pricing. And this is a market that shows very good value for operators when they're using super-spec rigs. And so, I think, our customers recognize that too. So yes, there is some pressure on leading-edge rates. And there is anecdotal numbers that float around as to what leading-edge rates are. But remember, we have a rig that goes out on a dayrate. And then we have a number of charges that layer on top of that rig as well that combine to make up our average revenue per day, which is a much higher number than what you hear on some of these anecdotal numbers being thrown around.
Yes. That's fair. Maybe to keep it like-for-like, could you characterize just dollars per day, how much the market has moved over the past quarter or 2? Any sort of ballpark there?
I think we'll pass on calling out any absolute numbers on that.
Your next question comes from James West with Evercore ISI.
Andy, Mark and Mark, I want to applaud you guys on taking the appropriate actions in removing iron from the market. You guys have always done the best thing for your shareholders and you're doing it once again.
Andy?
Thank you.
As you reviewed your horsepower during the quarter and decided to retire that 300,000. Is there additional horsepower that may be is on that kind of edge where it may be retired going forward? Or was this a complete thorough review, you're done for now and you won't reassess anytime in the near term?
This was a very thorough review, both on the drilling side and the pressure pumping and directional drilling across the board based on current market conditions, where our share price trades, valuations that are put on the company from outside versus inside. And so we think that we've done a good job in taking the write-downs on everything that we need to write down over any near term period. I think that taking 300,000 is a good number for us, and I'm very encouraged what I've seen and heard about other companies retiring equipment as well.
Right. Okay. Make sense. And then on the contract drilling side, I know that you're talking to our customers about standing up some rigs late this year, early next year. Could you maybe -- I know you don't want to quantify exactly, but give us some idea, is it a handful of rigs? Is it a nice step up in rig activity? If everything comes through and I know this is just conversations, not contracts yet, but kind of what's your sense of the magnitude of the potential improvement in the rig count?
I guess, if I had to qualify what that increase looks like today, handful or modest increase is the visibility that we have today, but there could be upside on that. I think we just don't know what all the operators intend to do yet. Some of them are working through their budgets, trying to quantify what they spent this year and what they may start with next year, that could cause more discussions on rigs going up other than what we know today. So I'm cautious on calling out exactly how many rigs that we could be putting up because there could be some upside to that in Q1 as well.
Your next question comes from Scott Gruber with Citigroup.
How much could the use of components from the retired frac pumps aid frac CapEx in '20? Could that to be meaningful or is that going to be limited?
It certainly has the potential, but I would say, it's a relatively small number on a quarterly basis in terms of overall CapEx budget. We did some rationalization already so far this year based on equipment that we were retiring. We probably had close to $10 million to $12 million savings in CapEx in the third quarter, maybe $5 million to $6 million capital savings in the fourth quarter. So I don't think we know what that looks like yet in 2020, but it gives you some of the magnitude of what we've seen so far.
Got it. And then on the rig side, should we still be thinking around 2,000 a day in rig CapEx? Or are you starting to see some deflations in components there?
It's still in that 2,000 a day level, or roughly 740,000 per year of solid operating is how we look at it closer. So -- but it's still in that level. Don't -- haven't really seen any deflation in that number per se. Some of it -- a lot of it's labor and we're not seeing any reductions in the labor. So we when we're capitalizing those projects, it's not just materials, but it also includes labor.
Got it. And I know you guys haven't set a budget for next year, but just some rough math with a modest bounce in activity, you're kind of in the ballpark of $100 million on frac maintenance, $100 on rigs and then you'll have some other spend. Should we be thinking about the low-200s figure? Should we be thinking about a high-200s figure? If you annualize 3Q, you are in the high-200s, but it seems like low-200s is possible.
Yes. Well, I appreciate the question. I think we're going to refrain from getting any discussions on what 2020 numbers look like yet. We'll start our process in a few weeks to take a deep dive into what we think that is. But suffice it to say, we're still focused on generating good free cash flow.
Your next question comes from Tommy Moll with Stephens Inc.
You mentioned earlier, Andy, that the difference between the dayrate versus the average revenue per day that you guys report. So if we look at, for example, your guidance for Q4 $23,500. Would you be willing to share how much of that is the ancillary piece that includes the other services? Or if you don't want to quantify that, could you just bridge us from what stacks on top of the dayrate to the average revenue per day that you report? I think this has caused a lot of confusion with all the commentary on dayrates and there's been some apples-to-oranges comparison. So anything you could do to help us straighten that out would help.
Yes. Kind of give it qualitatively. The number is in the range of a few thousands dollars per day, on average across our entire fleet. I give a lot of credit to the people in our drilling business. They've done a great job of providing ancillary equipment to operators that we get to charge for. We have a great drill pipe rental business along with other components and so all adds up into that number.
Okay. And if you don't mind sharing outside of the drill pipe rentals just what the other big components of that might be?
It's a variety of things. It could be charges for extra personnel on location. The drilling intensity has gone up so much over the last few years that the number of people that we provide to operators to actually operate the rig, whether it's during the drilling operations itself where the rig move has actually gone up. And we appreciate that our customer support us in terms of adding the extra staff on those rigs.
Okay. That helps to clarify quite a bit. And then sticking on the theme of land drilling but shifting over to the technology side. Your strategy has been to control both the full spectrum of hardware to include the directional piece and now to layer some software investments on top of that. Could you remind us what -- at a high level, what -- how you came to that strategy of wanting to control both sides? And then of the software side, if you could remind us, how much you've invested so far? And the extent to which you can scale that modest investment across the fleet versus how much more investment we might see going forward?
Yes. We're really excited about the technology programs that we have in place across Patterson-UTI in the various businesses and our ability to link these together over time to add value to the customers' wells. And the exciting part for us in terms of return on capital for shareholders, we don't need to build $25 million rigs right now or add large frac spreads, but we can invest in technology, which is the capital-light investment. And a great example of that is the Cortex operating system for the drilling rig. The investment in round numbers to engineer that system is in the $2 million to $3 million range, and so that's the project. To deploy that is in individual cost per rig, but a relatively low cost per rig to put that out.
So these numbers aren't big by any means, they fall off in the rounding of the capital budget. In fact, some of the -- a lot of the engineering cost are in the OpEx, because they are labor. So we don't capitalize those projects, they're just part of OpEx for the company. So very excited about the potential that this brings because it's going to improve the overall value that we can provide to the customers.
And as we start to roll these things out from moving from field test to more commercial type products, we'll be looking to monetize these in different ways in dayrates than we currently do with large assets. And excited about the potential it brings in the future. Again, it has the ability to improve the relative return on capital profile of the company.
Your next question comes from Kurt Hallead with RBC.
So the team there has made a tremendous emphasis on generating free cash flow through cycle, and obviously, you're kind of proven that out as you go through this dynamic here. Just kind of curious as to whether or not you'd give us an update on the mindset in terms of the deployment of cash and capital allocation vis-à-vis. Any incremental debt reduction from here? How you think about the share repurchase dynamic? Give us some color on that, that will be great.
Kurt, I think our record is pretty clear here that we've managed our debt levels carefully, taking down debt as we did in the quarter was something that we were extremely focused on and are proud of having accomplished. At the same time, we've also seen our stock priced at a level that we think is very, very attractive. The opportunity to use some of our free cash to both reduce debt as well as buy back shares seems to be a pretty attractive combination for us. It's hard for me to kind of sit here and tell you exactly what percentage will go in the future of free cash to debt reduction and what percentage will go to share buybacks. But my own feeling on that is that we manage to reduce debt about 15%, and shares by about 15%, and it's kind of interesting that they worked out so close.
Right. I appreciate that. I know that Andy -- sorry, Mark. Go ahead.
So I think that says a lot about how we think about it.
Yes. I appreciate that color, Mark. And then, Andy, I know you've mentioned you're not going to make any commentary on, like, any financial dynamics for 2020. Just at the bare minimum though, when you think about maintenance CapEx across your portfolio of businesses, what would that maintenance CapEx level look like right now?
I think it's hard to know what it looks like. On pressure pumping, Q4 is a good example, where margins are going to come down, revenues are going to come down. It's a blocky quarter with some of our spreads don't work the full quarter and maintenance CapEx is a function of the amount of hours that we put on equipment. So it's really going to depend on what schedule start to look like in 2020 and things like that on the pressure pumping side, on the drilling side. It's just too early to know what the rig count is going to look like. What kind of increase we're going to see in Q1 or Q2. We just don't have that level of visibility yet.
Your next question comes from Taylor Zurcher with Tudor, Pickering.
Looking at pressure pumping for Q4, just given the magnitude of the sequential revenue decline. Can you help us think about how much white space you actually have on the calendar for the 13 or 14 spreads you have out there? And then moving into Q1, remind us of those active spreads you have right now, how many are position in the northeast today?
I don't think, we've -- just kind of working backwards on your question, I don't think we've called that in a while, where our horsepower is and how much it's in each location.
In terms of the white space in the calendar, the best way I can describe it is to tell you that we've got some blocky chunks. It's much greater than it has been, and it is a combination of going into seasonality in the fourth quarter, along with some of the operators trying to contain their budgets. And then what happens in 2020 after that is still a bit of a question mark. The last two years in the industry, we've seen operators react in different ways. Two years ago, operators reacted by slowing down hard in the fourth quarter. This year they started slowing down in the third quarter. it's just too early to know what 2020 is going to shape up to be.
Okay. A follow-up on the rig side. You talked about potentially a handful of rig reactivation late this year, early next year. Clearly, some element of pricing pressure embedded in there. But as we think about conceivable these are new term contracts or maybe in the spot market, but what sort of term do you think you'd get for these incremental rigs that might go out there, is it a well-to-well type program 6 months? Or are there any operators out there that might actually want to contract an incremental rig for a full year?
Yes. I think, the bulk of these will be some kind of term contract typically in the 6-month to one year range is how that'll shape up.
And your next question comes from Chris Voie with Wells Fargo.
I guess, back to pressure pumping. So I understand that 4Q is going to be very messy, which makes sense. But maybe if you could help us bridge the gap from, let's say, 3Q to 1Q '20 in terms of presumably if activity rebounds in the first quarter, utilization should return to decent levels for what you have acted. So maybe first of all, to what extent you have the visibility for, let's say, keeping the 13 or maybe 12 fleets active before potentially growing that? And then secondly, if you could give any color on to what extent pricing would be lower in 1Q in terms of discussions for work starting then versus, let's say, mid-2019 levels?
Yes. It's the best way that I can kind of describe Q4 in terms of just kind of following up on one of the previous questions on what our white space looks like. We're going to end up with more white space in December than, say, November. And so that creates a lot of challenges in managing the crews across the entire quarter. And so we should see some improvement from that from December to January, as we get into the new year. But -- and then it is still a question mark as to much of the new work will take in the start of the 2020, as a number of operators are already having discussions with companies like ourselves to add potential spreads, but it's the pricing that's going to be a question mark and whether or not we like the economics. And I think we haven't reached that level in the discussions and we certainly haven't made any decisions yet on that. And that's why it makes a little bit tougher to give more color on what Q1 is going to look like in pressure pumping whereas in the rigs, we are in some more definitive discussions about putting up a number of rigs late in the quarter, early in Q1. In pressure pumping, we still have to continue those discussions and determine if we like the economics.
Okay. That's fair. And then maybe on the fixed cost side in pressure pumping, I think, you mentioned some work on facility closures and stuff like that. I don't think you mentioned exiting any basins per se. But can you give a sense of how much of a tailwind you might be able to get from fixed cost and lowering fixed cost as you get into 2020?
We'll give you more of an update on the next earnings calls for that. I mean, there's just so many moving pieces for us in the fourth quarter. And again, we're playing this for the long term, not the short term. We have a lot of good people and we don't want to make too many quick decisions on things that -- if we have some opportunities in the first quarter. So we'll give you more of an update on that when we do the call in February, but I appreciate the question.
Your next question comes from Vebs Vaishnav with Scotia Howard Weil.
I guess, just following up last question, Chris question. Are you implying that the first quarter rig count could be higher than fourth quarter? Or is it just that wherever we exit from fourth quarter we would see improvement in 1Q?
There is the potential that first quarter could be higher than fourth quarter, I don't think we fully know that yet. We are in discussions to put up, as we talked about, some rigs at the end of the fourth quarter and going into the first quarter.
So I think what we just don't know is the full extent that operators are going to make decisions to put up those rigs. As I mentioned earlier, with operators going into their budget season, I think they're trying to reconcile their full year, this year, their fourth quarter in terms of their budget. And I think we still have some operators that may make some decisions, it could be favorable for rig count in the first quarter, but we just don't know yet.
Got it. Got it. Just some clarification question. So if I'm not wrong, you will be left with about 1.3 million of horsepower, which, if I'm not mistaken, is around 23, 24 fleets versus the 13 that are working today. If I just do some back of the envelope math, it's implies that net of fluid ends, your EBITDA went about, like, from $5 million in 3Q to call it breakeven in 4Q. Could you help us just think about just the decline, is that more because of just white space? Or is that something to do with pricing?
So there is a mixture of things that are happening. So first off in terms of the number of spreads, spread size for us in terms of horsepower per spread has been increasing, as we've done more of the deep Delaware work and getting some a little bit steadier work in that area. So that's raised the amount of horsepower per spread, and that can fluctuate depending on what's happening between Texas and Northeast and Mid-Continent. Then as well with the blockiness that we have in the fourth quarter and the white space that we have in the calendar, that's certainly pulling down margins while we're still came personnel. So the fourth quarter just has various moving parts in there that make it more challenging with the seasonality and the budget constraint that some operators have. And then us trying to manage the spreads and manage the personnel.
Got it. So I guess, like -- the way I was going with that, let's -- if I understand the white space and then December basically shuts down, but if I think about first quarter I'm not trying to ask you for, like, a number. But just directionally, it should be, I don't know somewhere between third quarter and fourth quarter if I think about first quarter, just directionally. Is that fair way of thinking on a profitability per fleet basis?
Yes. I mean, profitability per fleet come down in the fourth quarter, but per spread, but the spreads aren't all operating for the entire fourth quarter. And that's -- so that's driving a lot of that challenge there on the profitability per spread on average. Then first quarter has the potential to be better. The exit directionally from December to January should see some improvement, but it's too early to know what that level of improvement is going to be.
Your next question comes from John Watson with Simmons Energy.
Andy, within drilling, is there any discernible difference between types of operators and their willingness or acceptance of some of the ancillary add-ons to revenue per day that you mentioned?
Yes. When I look across all the rigs that we're operating today, it's -- you can't really distinguish the different types of operators. We have large major oil companies and privates that are both renting pipe from us or putting extra personnel on rigs or renting various other pieces of equipment that we might offer as well. So it's not -- it's not that it's one type of customer and another it's fairly spread out evenly, I'd say, across the board. It's really about maximizing the overall efficiency that you can get out of using a high spec and super-spec rig today.
Sure. Okay. But you would say, there are certain customers that are less accepting or less willing to use those type of add-ons. I'm just trying to bridge the gap between some of the dayrate anecdotes versus with the actual market -- where the actual market is, if that makes sense?
Yes. I'd say it's fairly even across the board.
Okay. Okay. And then, as a follow-up, you spoke -- you gave OpEx per day guidance, and I'm looking towards 2020 with this question. In the past, we've talked about a mid 13,000 number eventually when OpEx normalizes. I'm guessing that's tough to achieve in a declining of flat rig count environment. But can you give us any help on where OpEx per day could trend next year assuming things are relatively flat?
I think that with the number that you called out, I think, OpEx that would be the normalized number. When rig counts coming down as fast as we did in the third quarter, it's hard to get it to that level. In a steady state, it could be at that level. But if we're reactivating rigs, we'll have forward personnel cost and a little bit of maintenance that would be in that number as well as we reactivate rigs. So it really depends on how you're modeling and what you consider steady versus reactivation periods.
Your next question comes from Waqar Syed with AltaCorp Capital.
A couple of questions. But first of all, for the capacity that you're retiring 300,000 hydraulic horsepower, when was the last time that capacity actually worked or did it work at all in the last three years or so?
For us, that particular horsepower did not work in the last three years. I mean, the market has just been so oversupplied that we just haven't needed it. And that certainly came in to play in the consideration for determining what horsepower retired and which horsepower stayed in our active list. But yes, so in the last three years, that 300,000 for the most part has not worked.
Okay. And what would you say was the kind of the average age of that equipment and how does that compare to the rest of the fleet?
Without getting into discussions about the ages of fleet, certainly that equipment would have been older. On average, probably was 3 to 4 years older on average than the current state of the fleet.
Okay. Fair enough. And then in terms of giving drilling efficiencies, could you give us any guidance on what you've seen in terms of footage drills per day or days per well? How the trend has been, maybe year-over-year? But more importantly, sequentially, how are you seeing efficiencies change, let's say, in the Delaware?
So I think efficiencies continue to improve in the Delaware. In terms of how fast we're drilling the wells, but the laterals also increase. So I think we've been seeing a trend where we've had more operators setup more pads with longer laterals and things are kind of leveling off. It's hard to see the needle moving significantly over the next year to improve efficiencies from where they are, we intend to try to do that with some of the technology that we're going to introduce. But it's not just about improving how fast we drill in days per well, but also improving the quality of the wellbore and repeatability. When you get a good well, you want to be able to do that over and over and not have the statistical tail, where you sometimes get a slower well occasionally in your database.
So just thinking about the efficiencies, I'd think that the industry overall has done a great job to improve them. And it's going to be a little bit more challenging to improve the needle over the next couple of years.
[Operator Instructions]. Your next question comes from Blake Gendron with Wolfe Research.
We don't have great visibility into what's being scrapped versus putting on the block for sale. I'm not insinuating that you're in the market for horsepower, trying to sell horsepower. But of the deals that come across your desk, could you just characterize at a high level, how much of it you think will never come back, never be sold regardless of price versus the assets that are for sale that are viable in the current market?
So when I think about the 300,000 horsepower that we're retiring, that's going away. That's going to be parted out, cut up, et cetera, and it's going away. And I suspect that many other companies are in a similar situation to us where they've got horsepower that they haven't worked in a while, and there is no reason why that horsepower should ever come back to the market. We'll rationalize some of that horsepower. If we've got some lower-hour components on some of it, we'll use some of those components on our active fleet because that just makes sense. But the 300,000 we're retiring, you won't see that back and I suspect that's similar with other companies as well.
And that's why I'm actually positive on the long term in pressure pumping. I know that's hard to have that kind of visibility today, but I do think as we discussed earlier that the demand side is going to rationalize -- sorry, the supply side is going to rationalize over time to move that industry utilization number up from where it is today, because we've just been oversupplied for too long.
Now there's definitely fair. Jumping over to drilling real quick. It's our view that the DUC drawdown, especially outside of the Permian probably unsustainable for a lot of folks next year even with a modest increase in the rig count. Is this something that operators are even talking about? Or in the instances where you have frac fleets that are following your own rigs, any sort of change in the cadence in drilling versus completion activity where potentially we could see higher-than-expected recovery next year, simply because there is not enough inventory of DUCs.
We don't get into a lot of discussions about drilled, but uncompleted wells. We just don't get a lot of visibility from the customers. I think most of the work we do, whether it's on the drilling or the completion side is just in line with steady activity where a pressure pumping spread is following a drilling rig. Now you've got a full pad and sometimes two full pads that are spaced out between the rig and the pressure pumping spread, and so that's going to cause changes in the DUC number as you work through that. But for the most part in our operations, things just move steady from one following with the other.
Okay. Great. And then one more if I can. It's kind of mind-boggling to me how tough it is to get credit for the free cash flow next year. It's going to be pretty robust for you guys, we can build up CapEx as we all have kind of laid out here on the Q&A. But I was wondering in terms of getting credit for that free cash flow, if you would potentially change maybe the split between buybacks and maybe upsizing dividend, kind of in the context of your biggest peer getting a whole a lot of credit because they are somewhat of a dividend play especially to considering market cap constraints and share liquidity as it relates to general [indiscernible] only investors?
Yes. We definitely pay attention to that. We definitely think about that. That's not lost on us. Frankly, we think that the course of action we're pursuing at this point is the correct course of action for the company, but we just emphasize at this time. And we consider this literally, I've said this many times at every Board meeting over the plus 20 years I've been involved in the company. We've a discussion about what's the right size for the dividend, what's the right size for the buyback, if it's appropriate. We'd have this conversation on a regular and repeated basis and I expect we'll do so again every quarter next year.
And so it's not something, which as I see it is fixed in stone, but something that we consider. And we understand that some companies are getting more credit for dividends, others we think are going to get a lot of credit for buybacks over a period of time. So we think this is a very sound, long-term strategy that we've been employing by which we've reduced our share count substantially over the past 18 months. We think that's been a very, very positive factor for shareholders. And so we're pleased with what we've done. I think it was the right thing to do. And obviously in the quarters to come we'll have to consider whether that continues to be the best course of action or alternative course is the right course.
Your next question comes from Chase Mulvehill with Bank of America.
I guess, I got two questions. The first one, if we look out 3 to 5 years and think about any changes that could happen to the current super-spec rig configuration. Do you expect to see any significant changes in design or configuration of the super-spec rig? And if so, what specifically do you see changing relative to rig technology?
Well, the good news for us is that I don't see any real change in what the super-spec rig is going to look like from a mechanical structure. I think the $20 million to $24 million that we were spending per rig when we were finalizing our build process was dollars well spent. And what we're excited about is being able to invest in software type technology or lighter capital type technology to layer on to these rigs to improve performance and give us other avenues to have commercial terms with our customers at the same time. And I don't see us having to do any major spend or capital investments to reconfigure the drilling rig even on a 3- to 5-year time line.
Okay. That's helpful. And I guess, maybe kind of along those lines, could you talk about the success you're having regarding automating and integrating directional drilling and then potentially any other opportunities you see to further integrate additional downhole drilling services into the rig platform?
Yes. We're still engineering and field testing various components today. So it's a little bit early to get into some of the details about that. But we' thought it was important back in September to get out there and at least show you the things that we are working on. Some things are in field test now, some things will be in field test early next year. And as we work our way through next year, happy to give updates from time to time on how that's going.
All right. Look forward to hearing more about that. And last one, real quick. You talked about customers looking to add some rigs in the first quarter. I'd be curious on your thoughts about whether you think E&Ps will try to level load activity in 2020? Or do you think they will actually do what they did this year and loaded up in the first half and slowdown in the back half?
Well, I think that's the question that's still is difficult to answer. As I mentioned earlier, two years ago, it was hit the brakes towards the fourth quarter, and this year we saw the slowdown starting in the third quarter. Maybe that's a trend that things are starting to get more level, as we get into 2020. But I think that it's just too early to know yet exactly what 2020 is going to look like in terms of how it's going to move from quarter-to-quarter.
There are no further questions at this time. I will now turn the call back over to Mark Siegel for closing remarks.
I'd like to thank all the investors and analysts for their participation in our call. And look forward to speaking with you as we report fourth quarter and year-end numbers in February. Thanks, everybody, for your time and trouble. Thanks.
Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.