Q4 2019 Earnings Call
Ladies and gentlemen, this is the operator today's conference is scheduled to begin momentarily.
All that time your lunch will again be placed on him. He is a cold. Thank you for your patience.
[music] U.S.
Deficit has fallen.
[music].
My name is Simon and I will be your conference operator.
Later today.
At this time I would like to welcome everyone to.
To be Patterson, UTI energy fourth quarter 2019 earnings conference call.
All lines have been placed on mute to prevent any background noise.
After the speaker's remarks, there will be a question and answer session.
I'd like to ask the.
During this time simply press Star then the number one on your telephone keypad.
If he would like to withdraw your question. Please press the pound Keith 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.
The results of the three months and year ended December 31st 2019.
Participating on today's call will be Mark Siegel, Chairman any Hendrix, Chief Executive Officer, and Andy Smith, Chief Financial Officer.
A quick reminder, that statements made in this conference call that state the companies are managements plans intentions beliefs.
Stations or predictions for the future are forward looking statements, but then meeting of the U.S. Private Securities Litigation Reform Act of 1990, but the Securities Act 1933, and its Securities Exchange Act of 1934. These forward looking statements are subject to risks and uncertainties as disclosed to the Companys annual report on form 10-K, and other filings with the FCC.
These risks and uncertainties could cause the companys actual results could differ materially from those suggest in such forward looking statements for the company expects.
The company undertakes no obligation to publicly update or revise any forward looking statement.
The company's FCC filings may be obtained by contacting the company, where the FCC and our available through the company's website and through the <unk>.
As he sees Edgar system statements made this conference call include non-GAAP financial measures the required reconciliations to GAAP financial measures are included on our website Www Dot P 80 energy Dot com and in the company's press release issued prior to this conference call.
And now it's my pleasure.
During the call over to Mark Siegel for some opening remarks, Mark Thanks, Mike Good morning, and welcome to Patterson UTI guys conference call for the fourth quarter of 2019. We're 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 31st.
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'll provide some closure.
Before turning the call over to questions Andy Thanks, Mark [noise].
As set forth in our earnings press release issued this morning.
Fourth quarter, we reported a net loss of $85.9 million were 44 cents per share on revenue of $492 million, an 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, a cash to shareholders through share repurchases of $250 million and dividend $33 million.
Additionally, net debt decreased by 70 $79 million during the year to $801 million at the end of 2019.
In late 2019, well there.
Mortgage were challenged for many energy companies the strength of our balance sheet, an 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 use the proceeds to both refinanced $300 million of debt due in 2022 and reduce the amount.
Outstanding under and reduce the amount outstanding under our bank term loan.
The early repayment of notes due in 2022 resulted in a pre tax charge a $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.
<unk> cash on the balance sheet, our nearest term debt maturities not until 2028.
Turning now to Capex. During 2019, we spent $348 million on Capex, a 46% reduction compared to 2018.
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 and amortization impairment expense to be $178 million.
DNA to be $30 million, and our effective tax rate to be approximately 20%.
With that I'll now turn the call early indicators.
Thanks, Andy the fourth quarter was one of transition afterwards.
Steady decline in activity through 2019.
Contract drilling hitting a bottom in rig count in 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 and contract drilling that in pressure pumping at this time.
We're.
Honestly optimistic about both businesses through the year at current commodity prices.
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 early in the fourth quarter, we were encouraged as our average rig count improved in December.
For 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.
Next question, our rig count or count decreased net of 10 rigs from the beginning to the ended the quarter.
We stacked 23 rigs primarily early in the core 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, we're highly unusual and substantially affected our rig operating cost.
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.
Yeah.
Additionally, we ended up carrying much of the labor expense associated with these rigs wall their 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 hired crews and.
Activate rigs in the Permian basin, while incurring costs related to stacking rigs in other basins.
The variations are rig count and the related revenues and expenses for rig mobilizations labor and repairs and maintenance introduce what can only be described is noise in our fourth quarter contract drilling results.
Both the.
Average rig revenue per operating day of $23980, an average rig direct cost per operating day of $15540 were higher than expected and resulted in lower than expected average rig margin per day.
For the first quarter, we expect a level of geographic fluctuation in our rig count or.
Hey, 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 time.
Currently all of our apex XK is in the Permian are working in our last two available apex peak days in the.
Basin are contracted to go back to work in the first quarter.
Accordingly in addition to one apex XK, we transferred from East, Texas to the Permian Basin in the fourth quarter, we expect to transfer an additional four rigs to the permit in the first quarter, including two apex XK is from Apple Asia into apex PK is from the mid con.
Considering the impact of higher mobilization of labor costs associated with the rig movements in 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 $23200 to $23500.
In an average rig operating cost per day of approximately $15000.
As fluctuations of rig activity decreased throughout 2020, we would expect or average rig operating cost per day decrease as well.
We are encouraged by the growing demand for rigs that are capable of using natural gas is 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 Highline 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 is 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 systems Division.
For power has the ability to build the.
Energy 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 14, marketing spreads and we stacked and eliminated the variable costs associated with one spread in October.
Over into 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.
The benefit.
The 10.8 million dollar sales tax refund that reduced direct operating costs.
While our pressure pumping gross margin in the fourth quarter exceeded our expectations. The current level 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 or operation and exit the market.
During the fourth.
Quarter, we closed one regional facility combined to others and reduced our overall cost structure.
While we made some headway to rightsize 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're also expanding our.
Putting 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 equation is headed into right direction, but the demand side remains challenge.
Industry activity has modestly improved from the fourth quarter.
Lows, but overall activity remains depressed in pricing on new work remains challenged.
One interesting trend in the market is the increasing interest in natural gas dual fuel capabilities and is 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 a below 5%.
Due to the actions, we have taken and continue to take.
Along with the horsepower retirements, we are seeing in the market. We believe that pressure pumping results should improve later in the year.
Turning now to directional drilling or directional drilling revenues were $38.6 million with the gross margin of $3.8 million.
As we expected our directional drilling.
Revenue in 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 the MP businesses.
Revenues in the fourth quarter were 20.
$1.5 million with the gross margin of $7.7 million.
For the first quarter, we expect to operational results similar to the fourth quarter.
With that I'll now turn the call back to Mark for his concluding remarks.
Thanks, Andy in 2019, we generated strong cash flow.
[noise] 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 long term debt by $150 million.
Well, we are not pleased with the market conditions. It to 27 up did 20.
19, we proactively responded to these tough market conditions, we reduced capital spending by 46% and focus 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 2000 2000.
20 in which we believe will further differentiate absolutely.
I'm pleased to announce today the company declared a quarterly cash dividend on its common stock of four cents per share to be paid on March 19th.
2020 to holders of record as of March Fiveth 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 will now I'd like to open the call for questions.
Thank you at this time I'd like to remind everyone that in order to ask a question. Please press Star then the number one on your telephone keypad.
Well pause for just a moment to can policy Cuban a roster.
Your first question comes from the line of that functionality with Scotiabank. Your line is open.
Hey, good morning, and thank you for taking my question.
I guess.
On the drilling side, you guys talked about how the.
Tradition in the rig count would still keep adding the good opex of 15000.
Can you.
Talk about like what is a nominal level that because they should think about by the end of the.
Sure so.
You certainly saw higher costs in Q4 with the amount of movement that we were describing today in the rig count that we had recounts coming down in certain basins movement to other basins recap rigs going back up.
So a lot of movement lot them mobilization and demobilization, all combined and so that that drives and cost in Q1 is.
Well, we're still having that but it's on the positive side as you know 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.
You know approximately 15000 per day on the cost side in Q1, you know thats not the norm that.
Is this movement in the rigs.
That also includes.
You know labor costs associated in other other things that happened first quarter taxes. So when you get away from that and you get to more normalized.
What would be a normal as cost per day.
To operate the rigs.
Part of its a function of how many total rigs were operating if you look back to into 2018. When we were operating over 180 drilling rigs that number was in the range of 13500 14000, a day at this level of activity the norm should be closer to the 14000.
Into 14500 today.
So we should get there as they level out after the mobilizations of the drilling rigs.
That's very helpful.
Is it we do you get you can talk about let's see assuming normalized opex of flooding default in Fife.
If we think about the margins that backlog for the 60 rigs.
How do they compare.
This is what we have seen in that's it CQ, which was more off.
Non-GAAP Opex corridor.
Well in the margins are going to be 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 you're going to roll.
Towards the leading edge and 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 a leading edge day.
Rates come down a little bit in 2019 is the rig counts come down we're not really seeing any movement and leading edge day rates from where we are today I'd say, they're roughly holding steady. So you do you have the net effect of contracts in previous years rolling towards leading edge, but at the same time, we're seeing leading edge dayrates.
Told relatively steady.
On the on the high spec rigs.
All right that's up let me thank you Sir.
Your next question comes from the line of Tommy Mall with Stephens, Inc. Your line is open.
Good morning, and thanks for taking my question.
Good morning timing.
I wanted to start on pressure pumping as you look across 2020.
Or even let's just say first half.
This 10 spreads <unk>.
<unk> is that the number that you have in mind is the right size of the footprint.
It's obviously had to come down pretty quickly.
In line with the market, but should we think about that as the.
Land run rate at this point in time or would you still or is it different direction.
So we've certainly operated more spreads in the past its where we are today, partly as a function of the decline in activity overall as in two.
2019, you know as you know pressure pumping activity follows rig count and the rig counts down well over 30% across 2019.
At the same time, we're encouraged by the fact that we're putting up some more rigs here in the first quarter and other companies, putting up some more rigs as well and I think that.
As bode well for future activity in 2024 pressure pumping.
Now that being said we have no current plans to activate any spreads.
The market still oversupplied, we'd like to see the market tighten up we'd like to see pricing improve and so that'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 is now being retired and not coming back to work and you also got you know and increasing rig activity at the same time, so but in terms of our particular.
And our our plans are you know to average 10 spreads.
No plans to activate.
And we'd like to see the Martin 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.
We look across.
2020.
I think the.
The capex budget will be well received.
The other moving pieces I'd be interested and comment on arduous priorities.
Arms of de levering versus share repurchases and how you think about balancing those two over say the.
12 month.
Yes, let me just start with the Capex you know, it's purely a maintenance capex for the work that we have the work that we're projecting with the addition of us little bit of growth Capex on the drilling side, where will 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 at a $150 million.
Ours 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 that expected 2020 will look probably slightly different numbers, but along the same kind of basic.
Proportions the.
The 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 at 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.
Rick.
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 on pumping Andy It sounds like you're taking a.
Additional actions to rightsize the cost base there.
Which certainly seems appropriate given the reduction in demand.
[music].
The question on the improvement in the second half the year. If there are no cost too to come out that.
Gives you confidence that you can get back up to.
An annualized EBITDA.
Run rate of the five or 6 billion.
In order to cover your maintenance Capex divided by the end of year.
Yes, I think there is an 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 theres some.
Permits we can make on efficiency and maintenance systems and some other areas that we've 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 that overall, there's still some things we can do within the systems.
To make sure that we.
Main profitable and competitive at this level.
I looked at the work that our guys are doing in the field. If some of the highest level efficiencies that you're going to get out of any spread anywhere in any basin and so the work that they're doing his top notch and that's not a question at all it's really about what are we doing on the back into.
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 I think there's more that we can do in 2020.
Gotcha.
A question on day rates across the us market.
It sounds based upon what we've been hearing that Permian rates.
Higher than elsewhere and you highlighted the.
Tightness in that market on the Super spec class of rigs how wide is the bifurcation rate in the Permian versus other markets is it sustainable.
I will.
Some color on and 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 these are mobile assets and we are moving rigs you know from east, Texas from Appalachian into the Permian.
And it's really.
Early because you've got other basins and it 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 asset. So it's not so much of a.
For initial in day rates, it's just more of a requirement for the assets in the basin.
How much is it to there's a rig from the northeast for the Permian roughly.
From the from the northeast to the Permian you're in the range half a million dollars are 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 and pressure pumping you flagged Oh 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 to 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.
Have any doubt because of the high performance of those crews that they'll get reposition but theres a transition there.
And so it's going to impact as.
Q1, maybe a little bit in Q2 will.
Keep you updated on that as we get into the next quarter, but it wasn't 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 on 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 did have contracts in hand already and then just just thinking about the broader market are you seeing the same sort of actions being taken.
From some of your competitors moving rigs from from outside the Permian into it just given this.
Supply demand dynamics and that base and moving forward.
Yes, so from my comments this should add up to five rigs if it didnt, 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.
So we would only do this with a term contract to move rigs like that from basically 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 and take these rigs and bring them into the basin and with the.
We have moving in and we actually think we couldn't be gaining share and in the Permian over the next couple of quarters.
Okay got it thanks guys.
Your next question comes from the line Praveen Narra with Raymond James Your line is open.
Hi.
Good morning, guys I guess I wanted to come back I, just want to come back to Scott's question on the pressure pumping side. So I guess, if we just reduce the fixed cost and without any benefit to pricing are much more utilization are we saying that we can basically covered with just that we can cover or 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 call help ourselves in one of the other contractors that you know 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 discuss this at the last conference. We were at early in January and but as we moved the rig count up in the industry, which I think will happen.
Across Q1 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 talk walk through kind of how you think of the calculus of spending on a major maintenance, obviously anything safety wise, obviously do but when we think about just major maintenance.
Does it need to have a certain payback period before.
Where you actually do it and if it doesn't give you don't see that are you willing to stack from there how should we think about how you're thinking about it.
So we've always funded maintenance capital and our pressure pumping business. We've been in this business for a long time and serve as a service quality in the field were at top tier performer and we've always funded.
Capital for the business.
One transition we made in 2019 is when we said we were retiring the horsepower that we retired then we all the sudden had components that are available. Good components are still on pump trailers are blenders that we can use in the maintenance process and so we've had.
You know cost savings in the range of call it $6 million to $8 million.
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, I'm not sure exactly if that number is going to be the same or or in that range.
Range, but we still have components that we can use so the only the only thing you've seen shift for 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 our spend efficiency there.
Okay. Thank you very much good.
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.
You will fuel and how Patterson spend a leader there and expects to 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 for companies that have dual school versus.
You know a conventional diesel.
Yes, and the uptake for dual fuel really started back in 2012.
I would say and it was primarily in northeastern the gas basins, where you had gas you had infrastructure and the cost of bring pipe.
Within a field over to a pad was a you know economically made sense to bring the natural gas over to the pad and run the frac spread 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 us.
The shift that we're seeing now is twofold, one in Texas, you got gas its trapped in the basin in West, Texas that doesn't bring a lot of value, but theres also.
Also a number of customers towards 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 will see operators invest within their fields in 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 side.
And that's actually improvement for the.
The operator sustainability score and 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.
I think you're going to see operators adjust accordingly, and we're well positioned for that you know in 2013 and 14, we were running a number of rigs I believe it was five or 100% natural gas.
We are running some rigs today off 100 or sit natural gas and I see that potentially growing as well as dual.
Fuel on both rigs and pressure pumping.
I just on that for pressure pumping you know there's been lots of talk over the past year and a half for so about electric Frac and when you look at it from a.
Greenhouse gas perspective.
From the customers lens is it much.
Rent for them.
In terms of their greenhouse gas reporting.
Whether they are 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. We're what are the auctions and what do those options mean form.
And we have suppliers that we work with that have data on the turbans as well the interesting thing about the turbans. It doesn't really get discussed as you can't really shut down a turbine when you're not.
Using it when you're not under full load a turbine near sea level is actually not that efficient and so you've got a lot of methane bypass and so.
You know 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%.
Placement and natural gas a full load.
And then you can shut them off when you're not using.
Has the potential produce better emission results for the operator at the wells.
Great. Thanks for the comments I'll turn it back.
Your next question comes from the line of Chriss 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 Exxon Mobil reimbursement just kind of get a better feel of the apples to apples trajectory from Q3 into Q4 now into Q1.
You know there's so many.
Things that affect that I think it's difficult to get to that answer of offhand I don't have that number in front of me.
Okay fair enough, but is it like what do you expect kind of just like marginal using.
We've got mode costs in there, but we've got no revenue in there I.
I think most of the higher than expected mode happened in the fourth quarters. So you've already guided easing in the first quarter. So it's already in the numbers in the first quarter.
Okay.
I appreciate that and then my thought was interesting it seems like regional pricing you know is largely the same despite pretty significant differences in utilization amongst some of the basins I 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.
Out of new contracts kind of in some of these softer regions.
Yes, I'm going to get on my Soapbox on this but companies in the high spec drilling business has always been disciplined I mean, we've been disciplined you know as long as we've been building.
First the high spec rigs and then transitioning to the Super spec rigs you've always.
Being disciplined in this market even in the depth of the downturn in 2016, so when the rig count moves up you see day rates move up when the rig counts come down you might see day rates come down a little bit.
But I think you know the the trajectory of the downward move of day rates has always been over discussed.
And there has always been more discipline in that market than I think this market gets credit for.
Oh, yeah. It does seem like it I appreciate it that's does it for me thanks for the time guys.
Your next question comes from the line of Kurt Hallead with RBC. Your line is open.
Hey, good morning.
Good morning occur.
Yes.
Hey, Andy as I was kind of curious say you know you guys you did a great job over the fall and pointing out the technologies that you're pushing out into the marketplace.
Right.
Then software applications operating systems, all those all those things I just wonder if you can kind of give us a an update on the progress the.
Adoption and the commercialization of or some of those technologies.
Sure you know 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 we're still field testing some of the components.
Apps like pipe ops oscillation and apps like enhanced auto driller are performing very well and so we're encouraged by how that.
Technologies, working and so we'll start to transition into more commercial models and expand.
The presidents and use of those on the rigs in 2020, but very excited because that technology is definitely moving into right direction and you don't want to come in the teams that we haven't Patterson UTI either working on those technologies, because they're making great progress.
Chris.
Okay, and how about the overall commercialization.
Well commercialization will happen more for us in 2020, and so we'll start to a transition some of that technology into.
Proven performance of some of the rigs.
We do have a number of contracts.
Have performance components in that that will be a boost for us in 2020.
Okay and I just wanted to follow up you you indicated obviously that you're moving some rigs from different markets into the Permian you're moving them.
On a contract basis, I'll say, some maybe conversation of other.
The 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 you know the.
<unk> 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, you know the operators pay for mode. So.
You know the.
This is that the rig counts going up because demand is improving and I think that's positive for pricing.
Okay, and then lastly, just on in context to the the Frac market that you indicated that some modest improvements in frac throughout the course of the year, so given that as a backdrop or how much additional frac capacity think would.
Need that come out on the market for first to get back into a balance situation.
Oh.
Well, we would all like to see more frac equipment leave the market I'm not sure that we see more leave at this point I think you've probably got all the major announcements that we've had I think on our side. We estimate there is probably what 5 million horsepower coming out.
So if you 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, I will see some increase in demand so.
A lot of its going to be demand driven at this point, which will be commodity driven and.
Just to see how 2020 plays out.
Hi, Thanks appreciate the color thanks, Andy expert.
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.
It's a bit on another call, but I just want to I want to come come to drilling capex.
Thank you guided to 180 million for 2020.
If I'm doing it right you know the maintenance Capex is probably within this ballpark of 110 or so.
So you got probably 70 million or so of kind of non.
Thats Capex could you just kind of help us understand what all your 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.
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 tongue, but but your estimate on the maintenance versus growth. The your assessment, a little bit low would be higher.
Okay all right.
And committing to performance based contracts.
When you hear your competitors.
Talked a lot about this could you talk about where you stand today own performance based contracts.
And you know if you think that that's the route.
That Patterson is going to take a you know as you kind of push a you know 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 we'd be nonstandard types. The.
And some of those contracts have performance components as well and.
Do we do pretty well on those performance components.
And I would see that growing over time, it's not that were.
Rig and putting it on performance basis, but we have components of performance that are in those contracts and will be taken more.
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 that overtime, 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 four to 500 more per day for performance.
Improvements and so that's kind of the additional up with we did on the day right.
Okay, and how 40, where do you think that can go because I mean that sounds pretty conservative if you think about the value proposition that year, providing to your customers.
So just maybe.
Do you think that's where we settle out at 500 a.
They are do you think you can kind of really pushed 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 and some of these.
Know technologies until later in 2020, and so I think given that we still have a number of.
Knowledge is in the pipeline that we're rolling out in 2020, and 21 that Theres certainly upside I think it you know to say it's level out would be a long way from that I think this is just we're not even in the first inning of this.
All right appreciate the color thanks, Andy.
Thanks.
Again, if you would like to ask a question. Please press Star then the number one on your telephone keypad.
Your next question comes on the line of Marc Bianchi with Cowen Your line is open.
Thanks.
I wanted to go back to Mark you you made a comment about potentially or.
Maybe hopefully increase the dividend later this year, if I'm doing my math right on the first quarter guidance kind of shakes out till like 79 or $80 million of EBITDA.
What sort of quarterly EBITDA run rate do you think you need to get too.
To be comfortable bumping up the dividend.
Yep.
Mark I I'm, not going to say anything more about other than the question was asked what do you see as your capital allocation plans and I said that you know I thought last year was a very good indication of our capital allocation plans, where we spent.
$250 million on buybacks at 100 and.
$50 million on debt reduction.
That ratio made a lot of sand so what I wanted to do.
At the same time was also called out the possibility that there might be an increase of a dividend in this next year, but I just want it is just put that on the table as being a possibility and when you get to the players.
Saying asking the question what amount of EBITDA is required that starts to get into being very specific for decision that our board will probably consider as we have considered at every board meeting, but will be next considered at our April board meeting. So I don't want to be more specific otherwise highlands hands to a specific.
EBITDA number or a specific dividend number.
Yeah, Mark I'll add that we've been talking at a number that conferences and explaining that we've had a priority around buybacks and at certain point, where we feel like we bought back enough of the shares and get the share count down that you know it make sense to look at the dividend because it just becomes more.
And with that.
Okay. Okay. That's helpful context. Thank you.
And there were no further questions at this time I will now turn the call back over to what presenters for any closing remarks.
Thanks, Simon I would like to thank everybody for joining us on Patterson UTI is conference call for the fourth quarter.
After 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.
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