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Patterson-UTI Energy Inc
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Ladies and gentlemen, my name is Simon and I will be your conference operator today. At this time, I would like to welcome everyone to the Patterson-UTI Energy Fourth Quarter 2019 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. [Operator Instructions] Thank you.
Mr. Mike Drickamer you may begin your conference.
Thank you, Simon. Good morning and on behalf of Patterson-UTI Energy, I'd like to welcome you to today's call to discuss the results of the three months and year ended December 31, 2019. Participating in today's call will be Mark Siegel, 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 US 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 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 those 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 fourth 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 December 31. 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. As set forth in our earnings press release issued this morning, for the fourth quarter, we reported a net loss of $85.9 million or $0.44 per share on revenue of $492 million and adjusted EBITDA of $97.3 million. We generated strong cash flow in 2019, which was used to both return capital to shareholders and reduce debt. We returned $283 million of cash to shareholders through share repurchases of $250 million and dividends of $33 million. Additionally, net debt decreased by $79 million during the year to $801 million at the end of 2019.
In late 2019 while the debt markets were challenged for many energy companies, the strength of our balance sheet and investment-grade rating allowed us to successfully extend near-term debt maturities. In the fourth quarter, we issued $350 million of notes due in 2029 and used the proceeds to both refinance $300 million of debt due in 2022 and reduced the amount of outstanding under -- and reduced the amount outstanding under our bank term loan. The early repayment of notes due in 2022 resulted in a pre-tax charge of $15.8 million included in our interest expense for the quarter. At this point, other than $100 million on the bank term loan due in 2022, which is sufficiently covered with cash on the balance sheet, our nearest term debt maturity is not until 2028.
Turning now to CapEx. During 2019 we spent $348 million on CapEx, a 46% reduction compared to 2018. In 2020, we expect to spend approximately $250 million on CapEx, which includes $180 million for drilling, $50 million for pressure pumping, and $20 million for all other businesses and general corporate items.
Capital spending in 2020 will once again be focused primarily on maintenance capital in order to maintain the quality of our equipment and provide for a high level of service quality for our customers.
Turning to the first quarter, we expect depreciation, depletion, amortization and impairment expense to be $178 million. SG&A to be $30 million and our effective tax rate to be approximately 20%.
With that, I'll now turn the call over to Andy Hendricks.
Thanks, Andy. The fourth quarter was one of transition after a steady decline in activity through 2019 with contract drilling hitting a bottom in rig count and pressure pumping activity slowing as customers reduced activity at year-end.
Customers are still working to finalize their budgets and while there is more visibility in contract drilling than in pressure pumping at this time, we are cautiously optimistic about both businesses through the year at current commodity prices.
In contract drilling, we believe our rig count bottomed in the fourth quarter and will modestly increase in early 2020. Despite falling activity early in the fourth quarter, we were encouraged as our average rig count improved in December for the first time in a year. Nonetheless, our average rig count for the fourth quarter fell to 123 rigs as we experienced greater than expected fluctuations in rig activity, which also negatively impacted our drilling operating costs.
To provide some perspective on the magnitude of fluctuation in our rig count, our count decreased a net of 10 rigs from the beginning to the end of the quarter. We stacked 23 rigs primarily early in the quarter, of which 10 rigs were later reactivated in the same quarter. In total, we reactivated 13 rigs during the fourth quarter. These changes in our rig count within the quarter were highly unusual and substantially affected our rig operating costs.
As mentioned, 10 rigs that were stacked early in the quarter were subsequently reactivated later in the quarter. On these rigs we recognize both revenues and expenses related to the demobilization and subsequent mobilization. Additionally, we ended up carrying much of the labor expense associated with these rigs while they were idle between jobs.
Geographically, relative strength in the Permian Basin partially offset continued weakness in other markets in the first quarter. This geographic mix shift required that we hire crews and activate rigs in the Permian Basin while incurring costs related to stacking rigs in other basins. The variations in our rig count and the related revenues and expenses for rig mobilizations, labor and repairs and maintenance introduce what can only be described as noise in our fourth quarter contract drilling results.
Both average rig revenue per operating day of $23,980 and average rig direct cost per operating day of $15,540 were higher than expected, and resulted in lower than expected average ring margin per day.
For the first quarter, we expect a level of geographic fluctuation in our rig count to remain relatively elevated, primarily as an improving rig count in the Permian will continue to offset softness, in most other markets. In the Permian Basin, we believe super-spec utilization is starting to tighten.
Currently all of our APEX-XKs in the Permian are working and our last 2 available APEX-PKs innovation are contracted to go back to work in the first quarter.
Accordingly, in addition to 1 APEX-XK we transferred from East Texas to the Permian Basin in the fourth quarter.
We expect to transfer an additional 4 rigs to the Permian in the first quarter including 2 APEX-XKs from Appalachia and 2 APEX-PKs from the Mid-Continent. Considering the impact of higher mobilization and labor costs associated with the rig movements and the seasonal increase in payroll taxes.
We expect the first quarter rig count to be similar to the fourth quarter with an average revenue per operating day in the range of $23,200 to $23,500 and an average rig operating cost per day of approximately $15,000.
As fluctuations in rig activity decreased throughout 2020, we would expect our average rig operating cost per day to decrease as well. We are encouraged by the growing demand for rigs that are capable of using natural gas as a fuel source, both dual fuel and 100% natural gas, as well as for rigs that can run off of electric utility power also known as high line power.
These rigs offer lower fuel costs given currently low natural gas prices and are more environmentally friendly due to reduced emissions. Patterson-UTI is a leader in natural gas-powered rigs with 60 rigs in our fleet capable of using natural gas as a fuel source.
Additionally, we are uniquely positioned to meet growing demand for high line powered electric rigs due to our current power electrical control system division. Current power has the ability to build the technology to connect drilling rigs to utility lines.
Turning now to pressure pumping, activity decreased throughout the fourth quarter and we reduced our marketing spread count accordingly. We started the fourth quarter with 14 marketing spreads and we stacked and eliminated the variable costs associated with 1 spread in October and 2 in November.
We exceeded our expectations for pressure pumping revenue and gross margin in the fourth quarter. As expected lower activity and pricing levels negatively impacted pressure pumping revenue and margin in the quarter.
Gross margin of $21.9 million for the fourth quarter included the benefit of a $10.8 million sales tax refund that reduced direct operating costs. While our pressure pumping gross margin in the fourth quarter exceeded our expectations the current level of pricing across the industry continues to be unsustainably low.
For the majority of the industry current pricing does not support the reinvestment of capital into the market and in some instances, the maintenance of capital already in the market. We are encouraged by the recent announcements of horsepower retirement. Additionally, some companies have decided to close their operations and exit the market.
During the fourth quarter, we closed 1 regional facility combined 2 others and reduced our overall cost structure. While we made some headway to right-size the business during a period of declining activity, we still have work to do in early 2020. In addition to efforts to reduce our overall cost structure, we are also expanding our marketing efforts so as to broaden our customer base as customers including majors on a dedicated basis become less predictable with their operational plans.
In terms of the outlook, the supply side of the equation is headed in the right direction but the demand side remains challenged. Industry activity has modestly improved from the fourth quarter lows, but overall activity remains depressed and pricing on new work remains challenged.
One interesting trend in the market is the increasing interest in natural gas dual fuel capabilities. And as and as we have been a leader in this area for years, we expect to benefit from this trend in 2020.
We expect to average 10 active spreads for the first quarter and will be negatively impacted by the sudden operational stoppage of a major oil company customer. Pressure pumping revenues for the first quarter are expected to be approximately $130 million, with a gross margin of low 5%.
Due to the actions we have taken, and continue to take along with the horsepower retirements we're seeing in the market. We believe that pressure pumping results should improve later in the year.
Turning now to directional drilling. Our directional drilling revenues were $38.6 million, with a gross margin of $3.8 million. As we expected our directional drilling revenue gross margin were negatively impacted by the lower rig count in the fourth quarter.
In addition, higher than expected cost for repair and maintenance also negatively impacted the fourth quarter margin. In 2020 we're going to front end load some development costs as well as CapEx in order to bring new technology to the market sooner. For the first quarter, taking into account the front end loaded development costs, we expect directional drilling revenues of $34 million with a gross profit margin of $2 million.
Turning now to our other operations which includes our rental, technology and E&P businesses, revenues in the fourth quarter were $21.5 million with a gross margin for $7.7 million. For the first quarter we expect operational results similar to the fourth quarter.
With that I will now turn the call back to Mark for his concluding remarks.
In 2019 we generated strong cash flow and further strengthened our financial position. During the year we spent $250 million to reduce our number of outstanding shares by more than 10% and we reduced our long-term debt by $150 million. While we are not pleased with the market conditions in 2019, we proactively responded to these tough market conditions. We reduced capital spending by 46% and focused our spending on maintaining the high-quality of our equipment.
We made strategic investments in automation and in performance technologies, a number of which will come to market in 2020, in which we believe will further differentiate Patterson-UTI. I am pleased to announce today the company declared a quarterly cash dividend on its common stock of $0.04 per share to be paid on March 19, 2020 to holders of record as of March 5, 2020.
With that I'd like to both commend and thank the hardworking men and women who make up this company. We appreciate your continuing efforts. Simon, we would now like to open the call for questions.
[Operator Instructions] Your first question comes from the line of Vebs Vaishnav with Scotiabank. Your line is open.
Hi, good morning and thank you for taking my question. I guess starting on the drilling side, you guys talked about how the fluctuation in the rig count would still keep a limited OpEx of 15,000. Can you talk about like where – what is a normal level that we could – we should think about by the end of the year?
Sure. So you certainly saw higher costs in Q4 with the amount of movement that we were describing today and the rig count that we had. Rig counts coming down in certain basins, move in to other basins, rigs going back up. So a lot of movement, a lot of mobilization, demobilization all combined. And so that drives the cost. In Q1 as well, we're still having that, but it's on the positive side is, the rig count is expected to move up modestly from where we are. So we're certainly encouraged by where that's going directionally.
Now with our projection of approximately 15,000 per day on the cost side in Q1, that's not the norm. That includes this movement in the rigs that also includes labor costs associated and other things that happened in the first quarter with taxes. So when you get away from that, and you get to more normalized, what would be a normalized cost per day to operate the rigs, part of it is a function of how many total rigs we're operating.
If you look back to end of 2018, when we were operating over 180 drilling rigs, that number was in the range of $13,500 to $14,000 a day. At this level of activity, the norm should be closer to the $14,000 to $14,500 today. So we should get there as things level out after the mobilization of the drilling rigs.
Got it. That’s very helpful. And is there a way to – you can talk about, so let's say, assuming normal OpEx of $14,000 to $14,500, if we think about the margins that are in your backlog for the 60 rigs, how do they compare versus what we have seen in, let's say, 3Q which was more of a normal OpEx quarter?
Well, the margins are going to be a function of the day rate. And what we're seeing on the day rate. We certainly have contracts that were signed in previous years that are going to roll towards the leading edge. And so, that will bring average revenue per day on drilling rigs down a little bit, but I'd like to qualify that by also saying that in terms of leading edge, while we saw leading edge day rates come down a little bit in 2019, as the rig counts come down, we're not really seeing any movement in leading edge day rates from where we are today. I'd say they're roughly holding steady. So you do have the net effect of contracts in previous years rolling towards leading edge. But at the same time, we're seeing leading edge day rates hold relatively steady on the high-spec rigs.
All right. That’s all for me. Thank you so much.
Your next question comes from the line of Tommy Moll with Stephens Inc. Your line is open.
Good morning, and thanks for taking my questions.
Good morning, Tommy.
I wanted to start on pressure pumping. As you look across 2020 or even, let's just say, first half, does 10 spreads – is that the number that you have in mind is the right size of the footprint? It, obviously, had to come down pretty quickly in line with the market, but should we think about that as the planned run rate at this point in time, or would you steer us a different direction?
So we've certainly operated more spreads in the past. It's where we are today, partly as a function of the decline in activity overall in 2019. As you know, pressure pumping activity follows rig count and the rig count's down well over 30% across 2019.
At the same time, we're encouraged by the fact that we are putting up some more rigs here in the first quarter. Another company is putting up some more rigs as well. And I think that does bode well for future activity in 2020 for pressure pumping. Now that being said, we have no current plans to activate any spreads. The market is still oversupplied. We'd like to see the market tightened up. We'd like to see pricing improve. And so it's why I said earlier, I am encouraged with the pressure pumping business throughout 2020 and even into 2021 both on the supply side where you've got so much horsepower that's now being retired and not coming back to work. And you also got an increasing rig activity at the same time. So -- but in terms of our particular plans, our plans are to average 10 spreads with no plans to activate and we'd like to see the market tightening up from where it is today.
Okay. Thank you, Andy, that's helpful. And as a follow-up I wanted to shift to capital allocation as we look across 2020. I think the CapEx budget will be well received. The other moving pieces I'd be interested in comments on priorities in terms of delevering versus share repurchases, and how you think about balancing those two over say the next 12 months?
Yes, let me just start with the CapEx. It's purely a maintenance CapEx for the work that we have, the work that we're projecting with the addition of a little bit of growth CapEx on the drilling side where we'll add some ancillary equipment to drilling rigs but there is revenue to offset that spend, but it's primarily maintenance CapEx. With that, I'll hand it over to Mark and let him talk about some of our longer-term strategies on allocation of capital over CapEx.
Andy, thank you. If we look back at 2019 and see that we spent $250 million to reduce our outstanding shares and $150 million to reduce our debt I think you get a pretty good idea of how we think about these two possibilities. And so, Tommy, I guess, the short answer is I'd expect that 2020 will look probably slightly different numbers, but along the same kind of basic proportions. The other thing that is not off the table is the possibility of increasing our dividend this year. The company is as you know one of the very few investment-grade credits and with a strong balance sheet we think we're in a position to do all kinds of things that other companies are not able to do.
Okay. Thank you, both. I will turn it back.
Thanks.
Your next question comes from the line of Scott Gruber with Citigroup. Your line is open.
Yes, good morning.
Good morning, Scott.
First question on pumping. Andy, it sounds like you're taking additional actions to right-size the cost base there, which certainly seems appropriate given the reduction in demand. The question on the improvement in the second half of the year, is there enough cost to come out that gives you confidence that you can get back up to an annualized EBITDA run rate of the $5 million or $6 million in order to cover your maintenance CapEx by the end of the year?
Yes, I think, there is. And I'm encouraged by some of the work that the teams have been doing both at the end of last year and at the start of this year. I think there's some improvements we can make on efficiency and maintenance systems and some other areas that we still got some work to do. As I mentioned, we closed one of the regional facilities. We consolidated two facilities, we may do some more of that. But overall, there's still some things we can do within the systems to make sure that we remain profitable and competitive at this level.
When I look at the work that our guys are doing in the field, it's some of the highest level of efficiencies that you're going to get out of any spread anywhere in any basin. And so, the work that they're doing is top notch. And that's not a question at all. It's really about what are we doing on the back end to – from the maintenance systems and other systems and what can we do to take a little bit more cost out of those structures. So that's where we're looking. We're looking at our internal efficiencies in order to do that. And, I think, there's more that we can do in 2020.
Got you. And then just a question on day rates across the U.S. market. It sounds, based upon what we've been hearing, the Permian rates are higher than elsewhere. And you highlighted the tightness in that market on the super-spec class of rigs. How wide is the bifurcation rates in the Permian versus other markets? Is it sustainable? Just some color on that dynamic would be appreciated.
Yeah. Because you're seeing rigs moving and we're moving rigs, I don't think you get a lot of bifurcation between the markets right now. I mean, these are mobile assets and we are moving rigs from East Texas from Appalachia into the Permian. And it's really, because you've got other basins that are just slowing down.
In 2019 – in the early part of 2019, we saw a big slowdown in Mid-Con. And so we had to adjust for that. The natural gas prices where they are, we're certainly seeing some slowdown in the natural gas basins, but these are mobile assets. So it's not so much of a differential in day rates. It's just more of a requirement for the assets in the basin.
And how much is it to move a rig from the Northeast to the Permian, roughly?
From the Northeast to the Permian, you're in the range $0.5 million or so, plus or minus.
Okay. That’s it for me. Thank you.
Your next question comes from the line of Taylor Zurcher with Tudor Pickering Holt. Your line is open.
Hey, good morning. Thank you. In pressure pumping, you flagged the operational outage from one of your big major oil companies in Q1. Could you help us think about the magnitude impact of that outage during Q1? And are those revenues and utilization for that work likely to tick up in Q2 and beyond?
So, yeah, we called it out, because it is significant to that business for us. We have and had two spreads working for a major oil company that stop working in a particular basin. And so, we're working to reposition those spreads with other customers, maybe other basins.
I don't have any doubt, because of the high-performance of those crews that they'll get repositioned, but there's a transition there. And so, it's going to impact us. Q1 maybe a little bit in Q2. We'll have to – we'll keep you updated on that as we get into the next quarter, but it was big enough to, we felt like we should, at least call it out.
Okay, got it. And on the drilling side, you called out six rigs that you're mobilizing into the Permian and I think in Q1 or maybe even in Q2. Are those rigs being moved there on a speculative basis, or do they have contracts in hand already? And then, just thinking about the broader market, are you seeing the same sort of actions being taken from some of your competitors, moving rigs from outside the permit into it, just given the supply that – supply/demand dynamics in that basin moving forward?
Yeah. So from my comments it should add up to five rigs. If it didn't, we apologize. But we have five rigs going into the Permian right now. We don't move rigs on spec. In general operators cover costs for mobilization. And so we would only do this with a term contract to move a rig like that from basin to basin. But we're very excited about our position in the Permian. We -- this is an area of strength for us. We do good work there. So when we have rigs that are available, we have customers that are interested in taking these rigs and bring them into the basin. And with the rigs that we have moving in, we actually think we could be gaining share in the Permian over the next couple of quarters.
Okay, got it. Thanks guys.
Your next question comes from the line of Praveen Narra with Raymond James. Your line is open.
Great. Good morning guys. I guess, I wanted to come back to Scott's question on the pressure roaming side. So I guess if we just reduce the fixed cost without any benefits to pricing or much more utilization, are we saying that we can basically cover it with just that? We can cover our maintenance CapEx with just the fixed cost benefit, or is that not a fair interpretation?
I think it's going to be more than that as we look out through the year. So we are going to do some more on the cost structure side as I mentioned. But I am encouraged with the increasing rig count that you're hearing to call out by ourselves and one of the other contractors that there's going to be a bit higher demand on the pressure pumping side as well and that's going to take more white space out of the calendar. We still have white space in the first quarter. We discussed this at the last conference we were at early in January and -- but as we move the rig count up in the industry, which I think will happen across Q1 and into Q2 then I think this takes white space out of the calendar in the industry for pressure pumping.
Great. And then I guess maybe if you could help us walk through, kind of, how you think of the calculus of spending on major maintenance. Obviously anything wise you'll obviously do. But when we think about just major maintenance, does it need to have a certain payback period before you actually do it? And if it doesn't -- if we don't see that, are you willing to stack from there, or how should we think about how you're thinking about it?
So we've always funded maintenance capital in our pressure pumping business. We've been in this business for a long time in terms of service quality in the field. We're a top-tier performer. And we've always funded the maintenance capital for the business. The one transition we made in 2019 is when we said we were retiring the horsepower that we retired then we all of a sudden had components that are available. Good components are still on pump trailers or blenders that we can use in the maintenance process.
And so we've had cost savings in the range of call it $6 million to $8 million of capital cost savings because we were able to reuse some of them. In 2019, we still think we'll be able to reuse more components in 2020. Not sure exactly if that number is going to be the same or in that range. But we still have components that we can use.
So the only thing you've seen shift on our side, we continue to fund the maintenance capital. But because of the horsepower we retired, we have components available from that horsepower to work into the maintenance process and improve our spend efficiency there.
Okay. Thank you very much guys.
Your next question comes from the line of Marc Bianchi with Cowen. Your line is open.
Thanks. Andy you mentioned in your prepared remarks about dual fuel and how Patterson has been a leader there and expect the benefit. Can you talk specifically about what customers are asking for? How you see kind of the requirements evolving? Is there an opportunity for any kind of price difference for companies that have dual fuel versus a conventional diesel?
Yes. And the uptake for dual fuel really started back in 2012 I would say and it was primarily in Northeast in the gas basins, where you had gas, you had infrastructure and the cost to bring pipe within a field over to your pad was economically made sense to bring the natural gas over to the pad and run the frac spreads.
So on any given day in the Northeast U.S. historically, we've probably been running as much or more dual fuel operations as anybody across the U. S. The shift that we're seeing now is twofold: one in Texas, you've got gas that's trapped in the basin in West Texas that doesn't bring a lot of value but there's also a number of customers for which sustainability is becoming more important.
And when you combine those two things that are happening in Texas, we're going to see an increase in the demand for dual fuel spreads in Texas, we'll see operators invest within their fields and infrastructure to bring gas to frac sites, potentially early enough to power a drilling rig by natural gas. And so we see an increase in that, both from the economics but also from sustainability.
When we are burning natural gas, it lowers the emissions at the well site. And that's actually an improvement for the operator sustainability score to get those emissions down. And that's becoming more important for investors. We saw that trend in Europe a few years ago. We have a European investor base with various pension funds and other mutual and hedge funds in Europe but it's becoming more important in the U.S. as you've all heard in the news here lately.
And I think you're going to see operators adjust accordingly. And we're well positioned for that. In 2013 and 2014 we were running a number of rigs, I believe that was five of off 100% natural gas. We are running some rigs today of 100% natural gas. And I see that potentially growing as well as dual fuel on both rigs and pressure pumping.
Just on that for pressure pumping, there's been lots of talk over the past 1.5 years or so about electric frac. And when you look at it from a greenhouse gas perspective from the customers' lens, is it much different for them in terms of their greenhouse gas reporting whether they're using electric frac or dual fuel?
So I don't want to preempt some work that we're currently doing but we are in the middle of a study for our emissions for all of our businesses at the well sites both drilling and pressure pumping. Because we think our operators need to understand where they are today, what are the options and what do those options mean for them. And we have suppliers that we work with that have data on the turbines as well.
The interesting thing about the turbines it doesn't really get discussed is you can't really shut down a turbine when you're not using it. When you're not under full load, the turbine in your sea level is actually not that efficient. And so you've got a lot of methane bypass. And so there – I don't want to preempt anything but it certainly looks like some of the newer dual fuel high horsepower diesel engines where you can get 85% displacement in natural gas at full load and then you can shut them off when you're not using and has the potential to produce better emission results for the operator at the well side.
Great. Thanks for the comments. I will turn it back.
Your next question comes from the line of Chris Snyder with Deutsche Bank. Your line is open.
Hey, thanks for taking my question. Can you just maybe provide some color on what the average rig day rate in Q4 would have been ex-Moab reimbursement? Just so we can kind of get a better feel of the apples-to-apples trajectory from Q3 into Q4 and now into Q1?
There's so many things that affect that. I think it's difficult to get to that answer off hand and I don't have that number in front of me.
Okay, fair enough. But is it like would you expect kind of just like marginal easing?
We've got Moab costs in there, but we've got Moab revenue in there. I think most of the higher-than-expected Moab happened in the fourth quarter. So, you've already got it easing in the first quarter. So, it's already in the numbers in the first quarter.
Okay. Appreciate that. And then -- I thought it was interesting. It seems like regional pricing is largely the same despite pretty significant differences in utilization amongst some of the basins. Should we take this to mean that companies are being pretty disciplined when it comes to bidding idle rigs, or is it just that there hasn't been a ton of new contracts kind of in some of these softer regions?
I'm going to get on my soapbox on this. But companies in the high-spec drilling business had always been disciplined. I mean we've been disciplined as long as we've been building first the high-spec rigs and then transitioning to the super-spec rigs, you've always seen discipline in this market even in the depths of the downturn of 2016.
So, when the rig count moves up, you see day rates move up. When the rig count come down, you might see day rates come down a little bit. But I think the trajectory of the downward move of day rates has always been over-discussed and there's always been more discipline in that market than I think this market gets credit for.
Yes, does seem like it. I appreciate it. That's it for me. Thanks for the time guys.
Your next question comes from the line of Kurt Hallead with RBC.
Hey, good morning.
Good morning.
Hi, Kurt.
Hey guys. Andy I was kind of curious you guys did a great job over the fall in pointing out the technologies that you're pushing out into the marketplace, algorithms, software, applications, operating systems, all those things. Just wondering if you can kind of give us an update on the progress, the adoption, and the commercialization of some of those technologies?
Sure. Just to give you a little bit of view on it. With our Cortex operating system that we're running on drilling rigs, we have that out on nine drilling rigs right now where we're still field-testing some of the components, apps like Pipe Oscillation and apps like Enhanced Auto Driller are performing very well. And so we're encouraged by how that technology is working and so we'll start to transition into more commercial models and expand the presence and use of those on the rigs in 2020. But very excited because that technology is definitely moving in the right direction and I want to commend the teams that we have at Patterson-UTI that are working on those technologies because they're making great progress.
Okay. And how about the overall commercialization?
Well, commercialization will happen more for us in 2020. And so we'll start to transition some of that technology into improving performance of some of the rigs. We do have a number of contracts that have performance components and that will be a boost for us in 2020.
Okay. And I just want to follow-up. You indicated obviously that you're moving some rigs from different markets into the Permian, you're moving them on a contract basis, also some maybe conversation of other rigs moving around the chessboard so to speak. So when you look at it holistically, do you think that these rig moves could have a potential negative impact on pricing in the Permian?
No not at all. There's too much discipline in that market. The rig count is going up because the demand is going up. And I think that's positive for pricing in the Permian over the long term. It's not that we're moving rigs in there on a spec basis. We're moving rigs in there because we have long-term contracts. And in general like, I mentioned the operators pay for most. So the cases that the rig count is going up because demand is improving and I think that's positive for pricing.
Okay. And then lastly just in context of the frac market you indicated some modest improvements in frac throughout the course of the year. So given that as a backdrop, how much additional frac capacity, do you think would need to come out of the market for us to get back into a balanced situation?
Well, we would all like to see more frac equipment, we leave the market. I'm not sure that we see more leave at this point. I think you probably got all the major announcements that we've had. I think on our side, we estimate there's probably what 5 million horsepower coming out. So if you're taking 5 million horsepower out of the market, that's certainly a step in the right direction a big step in the right direction.
And with the rig count coming up in Q1 and potentially in Q2, we'll see some increase in demand. So a lot of it's going to be demand driven at this point which will be commodity driven and we'll just have to see how 2020 plays out.
Thanks. Appreciate the color. Thanks Andy.
Thanks Kurt.
Your next question comes from the line of Chase Mulvehill with Bank of America. Your line is open.
Hey, good morning. I'm not sure if this was discussed. I've been in another call, but I just want to come to drilling CapEx. I think you guided to $180 million for 2010. If I'm doing it right, the maintenance CapEx is probably within the ballpark of $110 million or so. So you got probably $70 million or so of kind of non-maintenance CapEx. Could you just kind of help us understand what all you're spending on there? And how additive that can be to revenue or to EBITDA in 2020?
Yes. I would say that the maintenance CapEx is higher, although we still have growth CapEx in there. So the maintenance CapEx being a little bit higher. What's left in the growth is just adding components to rigs, but those components in most cases are covered by additional revenue that we get off the contract at the same time. But your estimate on the maintenance versus growth your estimate is a little bit low, it would be higher.
Okay. All right. And coming to performance-based contracts one of your competitors we talked a lot about this, could you talk about where you stand today on performance-based contracts? And if you think that, that's the route that Patterson is going to take as you kind of push more technology and digitalization across the industry?
So we have about 20% of the term day rate contracts that we work on today, that you would say would be non-standard types of contracts and some of those contracts have performance components as well. And we do pretty well on those performance components. And I would see that growing over time.
It's not that we're doing the entire rig and putting it on a performance basis, but we have components of performance that are in those contracts and we'll be taking more of those as we roll out some of these technology pieces, because we think the technology offers improved efficiency for the operators. And it's something that we want to recoup our investment on. So that's how we see doing that. And I think you'll see more of that over time, because I think the technology will bring value.
And so on the performance-based rigs, or contracts that you're doing today, could you maybe characterize the profitability or the cash margin profile of those versus kind of some of the more traditional type contracts?
I would say, the components pay us in the range of $400 to $500 more per day for performance improvements. And so, that's kind of the additional uplift we get on the day rate.
Okay. And how far – where do you think that can go? Because, I mean, that sounds pretty conservative, if you think about the value proposition that you're providing to your customers. So just maybe – do you think that's where we settle out at $500 a day, or do you think you can kind of really push that? And if so, where do you think you can push it?
Well, I think, we're in the very early days of technology. I mean, we're still field testing things. We're not going to be commercial on some of these technologies until later in 2020. And so, I think, given that we still have a number of technologies in the pipeline that we're rolling out in 2020 and 2021 that there's certainly upside. I think it – to say it's level out would be a long way from that. I think that this is just – we're not even in the first inning of this.
All right. I appreciate the color. Thanks, Andy.
Thanks.
[Operator Instructions] Your next question comes from the line of Marc Bianchi with Cowen. Your line is open.
Thanks. I wanted to go back to – Mark, you made the comment about potentially or maybe hopefully increase the dividend later this year. If I'm doing my math right on the first quarter guide, I think, it kind of shakes out to like to $79 million or $80 million of EBITDA. What sort of quarterly EBITDA run rate do you think you need to get to, to be comfortable bumping up the dividend?
Marc, I'm not going to say anything more about it, other than – the question was asked, what do you see as your capital allocation plans and I said that I thought last year was a very good indication of our capital allocation plans where we spent $250 million on buybacks and $150 million on debt reduction. I thought that ratio made a lot of sense. And what I wanted to do, at the same time, was also call out the possibility that there might be an increase of a dividend in this next year.
And I just wanted to just put that on the table as being a possibility. Now, when you get to the point of saying – asking the question what amount of EBITDA is required, that starts to get into being very specific for a decision that our Board will probably consider, as we have considered at every Board meeting, but will be next considered in our April Board meeting. So I don't want to be more specific. I don't want to tie anyone's hands to a specific EBITDA number or a specific dividend number.
Marc, I'll add that we've been talking at a number of the conferences and explaining that we've had a priority around buybacks. And at a certain point where we feel like we bought back enough of the shares and get the share count down that it makes sense to look at the dividend because it just becomes more sustainable at that point.
Okay, that’s helpful context. Thank you.
And there are no further questions at this time. I will now turn the call back over to our presenters for any closing remarks.
Thanks Simon. I would like to thank everybody for joining us on Patterson-UTI's conference call for the fourth quarter of 2019 and look forward to speaking with you after our first quarter. Thanks everybody.
Ladies and gentlemen this concludes today's conference call. You may now disconnect.