Q3 2021 Patterson-UTI Energy Inc Earnings Call
<unk> per share consolidated adjusted EBITDA increased to $51 1 million.
Within our segments in contract drilling our average rig count improved to 80 rigs from 73 in the second quarter.
This increase in the rig count drove an 11% increase in total contract drilling revenues and gross margin.
On a per day basis, the average rig margin during the third quarter increased slightly to $6300 as an increase in average revenue per rig day was largely offset by a similar increase in average cost per day.
At September 32021, Patterson had term contracts for drilling rigs in the U S providing for approximately $286 million of future day rate drilling revenue and pioneer had another $64 million.
Based on contracts currently in place in the U S and including the rigs from pioneer we expect an average of 53 rigs operating under term contracts during the fourth quarter at an average of 35 rigs operating under term contracts during the four quarters ending September 32022.
For the fourth quarter, we expect activity growth will be robust.
Patterson UTI Standalone basis, our average rig count is expected to increase by 13 rigs quarter over quarter to 93 rigs in the fourth quarter.
The U S rigs of pioneer are expected to contribute another 13 active rigs to our average rig count, bringing our total expected average rig count in the U S to 106 rigs for the fourth quarter.
Yes.
General oilfield inflation, including the cost of labor continues to be a challenge in September we initiated a wage increase for rig based employees, which is expected to increase our average cost per rig day by approximately $600 per day.
We expect to ultimately recover this expense from customers in the form of higher day rates.
Additionally, we also expect a further increase in rig reactivation expenses during the fourth quarter due to both a larger number of rig reactivation is to support the expected growth in our rig count and the rising cost of rig rig reactivation.
In addition to higher labor expenses for the rig reactivation cost of restock the rigs have increased.
The growth in our rig count is expected to lead to revenue growth in the fourth quarter.
On a per day basis, the revenue benefit from the pass through of higher wages is expected to be largely offset by various items. Despite.
Despite recent strength in leading edge day rates many of the rigs being activated were contracted in late summer and in some of the weaker regions, where day rates have not been as strong in.
In the near term, we also expect lower ancillary revenue on a per rig basis, as we look to replenish our available inventory of ancillary parts and equipment.
Additionally, Additionally, the integration of the pioneer rigs into our fleet has a negative impact on our average daily revenue.
Therefore, the result is that we expect average revenue per rig day in the U S to increase slightly in the fourth quarter to approximately $21600.
With the increased increased costs for labor and rig reactivation.
We expect the average rig operating cost per day in the U S to increased to $16100 per day.
I want to emphasize that we do not see this fourth quarter level of cost per day in the U S is the new normal our estimate of fourth quarter cost in the U. S include approximately $900 per day of rig reactivation costs, which should come back out of our cost when the pace of rig reactivation slows.
Internationally, we expect the pioneer rigs in Colombia will generate approximately $15 million of revenue in the fourth quarter with approximately $4 million of gross profit.
In pressure pumping during the third quarter, we benefited from better pricing more simulcast <unk> work and the full quarter impact of two spreads that were reactivated during the second quarter.
Pressure pumping adjusted EBITDA for the third quarter more than doubled from the second quarter to $16 $1 million, while pressure pumping revenues increased by 36% to $153 million.
For the fourth quarter, despite expecting lower utilization due to the holidays and potential weather delays pressure pumping revenue is expected to increase to approximately $167 million while pressure pumping gross margin is expected to increase to approximately $18 $5 million.
Turning now to direct to directional drilling gross profit for the third quarter increased 35% to $3 4 million as revenues increased 28% to $31 $7 million.
For the fourth quarter, we expect revenues to increase to approximately $32 $5 million with a gross profit of approximately $4 5 million.
Revenues at our other operations, which includes our rental technology and E&P businesses improved to $15 6 million and gross margin improved to $5 $2 million in the third quarter for.
For the fourth quarter, we expect both revenues and gross profit to be similar to third quarter levels.
Before I turn the call back to Andy Let me touch briefly on the acquisition of Pioneer Energy services.
We completed this acquisition on October one and therefore, we expect a full quarter contribution from pioneer during the fourth quarter.
We have begun the process to divest the production services business and as such we expect to report these segments as discontinued operations going forward.
On a consolidated basis, including the impact from pioneer for the fourth quarter, we expect total depreciation depletion amortization and impairment expense of approximately $145 million.
Selling general and administrative expense is expected to be approximately $24 million for the fourth quarter for the full year 2021, we expect an effective tax rate of approximately 17%.
Including the shares issued as part of the pioneer acquisition, we expect the fourth quarter average share count to be approximately 216 million shares.
We are maintaining our expectation for capital spending with capex of $165 million for the year, but with supply chain disruptions. We may not we may not spend all of this amount in 2021.
Also we will be paying a quarterly cash dividend of <unk> <unk> per share on December 16, 2021 to holders of record as of December 2021.
With that I'll now turn the call back over to Andy Hendricks.
Thanks, Andy.
As I previously mentioned it is a very exciting time for the industry and for Patterson UTI, given the increasing demand for services.
As demand increases based on both discussions with our customers regarding their drilling and completions plans and also looking at the global oil supply demand macro over the next year.
As well E&ps are looking to reduce emissions and Patterson UTI has a leadership position in a number of technologies to help achieve this.
Let's start with the macro.
We have crude stocks being drawn down around the world and U S inventories are below the five year average demand for oil is forecasted by IAA to rise while OPEC plus we stated they will hold to their previously announced increased with the combined group's production.
In the U S. Our industry rig count is only around 540 rigs today and while some activity demand projections show that it could go to $650 to 700 rigs in 2022. This still may not be sufficient to fully offset petroleum demand growth. So we could have current oil prices for a while and the associated rig activity demand that go.
Along with that.
For Patterson UTI based on conversations with customers, we expect strong growth in drilling activity in the fourth quarter and these conversations suggest this robust growth in activity will continue into 2022, even while public E&P show capital discipline and return cash to shareholders.
However, even with the activity increases that we've seen over the last couple of months. It's interesting to note that these increases are largely based on WTO trading around $70 a barrel.
And it's only in the last few weeks that we've had inquiries for rig based on WTO at $75.
So we've yet to enter any meaningful discussions regarding an increase in activity based on where we are today with WTO around $80.
Additionally, public operators will soon be setting their 2022 budgets with a higher price deck.
Just on all of this I believe that if oil remains above $70 and right. Now there is no underlying forecasted increase in supply that says otherwise, we will see increasing activity due both to higher commodity prices and the higher E&P capex budgets in 2022.
All that being said how much growth the industry ultimately sees in drilling and completion activity in 'twenty. Two is largely will largely be a function of pricing for these services versus the cost to activate and staff the equipment.
Based on the current economics for reactivation, we believe that across the industry. The availability of equipment that can be economically reactivated at current pricing is nearly exhausted.
This relative tightness is driving price increases for our services and while we have seen cost increases. We've also seen recent leading edge price increases over the last couple of months and we believe that further pricing increases are attainable going forward, meaning we expect to see net price increases with improving margins in 2022.
Overall, we are very encouraged by the macro by the conversations we're having today with our customers.
The uptake of technologies to reduce emissions, such as eco cell and especially by the increasing demand and pricing for our services into 2022.
With that we'd like to thank all the employees for their hard work efforts and successes.
Julianne, we'd now like to open the call to questions.
At this time, if you'd like to ask a question. Please press star followed by the number one on your telephone keypad.
To withdraw your question. Please press star one again.
Well pause for just a moment to compile the Q&A roster.
And our first question comes from Ian Macpherson from Piper Sandler. Please go ahead. Your line is open.
Thanks, Good morning, Andy I appreciate Youre opening proclamation that were officially tight.
And I wanted to follow up on that.
It looks like Youre, even excluding.
Pioneer that youre outpacing the industry rig adds here in Q4, but.
Thank you.
You have if you are running into low hundreds I have you at around 160, plus total quote unquote Super specs in house, but you say that the available spare spares inventory and the industry is not necessarily economic to reactivate at current pricing could you bridge that for me a little bit in terms of.
What kind of day rates, you would like or you would require in order for Patterson to bring another call. It couple of your next couple of Desert reactivation is out next year and what those would cost and what kind of further day rate increases would would.
Enable that.
Yeah. Good morning, So we're really excited about the demand we're seeing and also about the.
The leading edge price movement upwards, we've seen over the last month or so.
When you look at the rig market and like I said, we're essentially sold out of the X K and PK apex's.
In West, Texas in the Permian right now and so when you look at the market and we do the analysis on on what we're trying to get.
<unk> has to move up and Thats why its been moving up so there is the cost to reactivate the rigs, which has moved up because we've been through a big downturn, but we have to put consumables back on the rigs and we've done a wage increase for the people in the field on the drilling rigs and so when you combine all of that and that's going to move our opex per day.
And so we have to get better pricing. So like I said, we're very excited about what we're seeing.
That leads us to believe that it is not a problem to get those levels of pricing to be able to put those rigs back to work and so our expect our activity to continue to increase.
But what I would say the market's tight I'm talking about what we consider the most capable rigs in the U S. The newest rigs built.
That we were still building in 2014 and early 2015, those rigs that were fully kitted out back in those years are essentially sold out.
And I think that you said that a lot of Europe.
A lot of reactivation is coming in Q4, but reflective more of summer pricing than todays pricing, which has moved quite a bit.
If we think about rolling off your 900 Bucks a day of reactivation costs in Q4, and Youre going to continue to melt up towards leading edge from Q4 into the first half.
It seems like normalized margins with those adjustments for the first half could easily be between $708000. A day would you take exception with that math.
No that that kind of falls in line the way we look at it of course, we're going to be operating a large number of rigs as we go into 2022 and <unk>.
Take some time for everything to move up at the leading edge is definitely moving out.
Yes.
Can I squeeze in one more can you can you tell me for your Columbia guidance, what that utilization implies for Columbia, and if there is any upside to that.
Numbers in the near term or if you see that more steady state until you.
Digest and integrate a little bit in that new market, yes.
Yes for US, we're really excited about the operations and the potential in Colombia that has a great team that business has been running for 14 years down there, they're well respected by their customers.
And being a part of Patterson UTI give them a lot of upside and a lot of potential and so we see the potential for growth down there over the next year and we will put capital into that business, where it makes sense, but given today's market and today's oil prices. We think that will happen. So we do see some we do see growth potential down there.
But we will be careful about how we're calling it that out that market is not near the size of the U S and so we don't want to price signal by giving too much information in the public domain.
Fair enough. Thanks.
Thanks, Andy.
Yes.
Your next question comes from Connor Lynagh from Morgan Stanley. Please go ahead. Your line is open.
Yes, Thanks, I appreciate all the context.
The cost items and I wanted to I wanted to hone in on the labor side of things, obviously wages in the oilfields have been under pressure for some time now I'm curious at this point with some of the other industries that you compete with for Labor do you offer a competitive wage to offer a premium wage base.
The question is is driving to how hard is it to attract talent and do you feel that youre going to need to raise prices again.
When activity continues to improve.
So when you look at how we've treated the wages for the people on the drilling rigs and we'll talk about the drilling rigs thats the largest business we have of course.
We went through a big downturn after 14 into 15 and 16, we didnt reduce the wages on the drilling rigs and so we've kept the wages steady and this is actually the first increase that we've been able to give.
And the market is driving that but we offer a very competitive wage and it's not just about the hourly but when you look at the amount of overtime that an individual gets when they are on a two week hitch on the drilling rig these are very competitive wages in the market.
Wage increase.
Very competitive versus other industries, whether it's trucking or working in warehouses or construction or home depot. So we're very comfortable with where we're at today I do not see us having to raise wages in the field.
Anytime in the foreseeable future right now because I do believe we're very competitive where we are where we've put them.
Okay got it.
Maybe just another sort of cost related question more on the pressure pumping side of things.
So what I'm wondering is as we as we look at incremental reactivation.
I mean, it seems that your your actions would indicate that pricing is sufficient to support the economics of its reactivation, but I guess the question is twofold.
Do you need further pricing to justify more or is it just a question of if the demand being there Andy.
How much would it cost you have substantial upgrades in deferred maintenance that needs to occur to do that.
Yes. This is similar to say $2016 $17 18, as we came out of that one.
<unk>.
Early spreads that you activate are always the easiest and the most cost effective to activate and it's similar with US This time and probably similar to a lot of our peers in this sector when Europe when you're activating those early spreads you are in that $2 million to $3 million range and then as you work into spreads into your and your overall.
Fleet, it's going to cost you more.
So there is the activation cost there is also the cost in some cases on some spreads where we're swapping engines on trailers and so we consider the reactivation costs and the cost to swap engines on trailers for.
For the newer technology and we consider all of that when we're looking at the pricing for the job. So not just the reactivation, but in some cases also the engine swaps as well we think absolutely the pricing is there today.
For what we're doing in terms of reactivation.
We get into 2022 sure.
Cost to activate spreads on just the reactivation cost alone is going to move up a little bit more.
But I do think that the market is going to support the pricing I think that this is across the board across the industry.
We're all looking at the same challenge and.
Along with the labor shortages that we're seeing where we're having to spend more money and work harder to recruit people and train people. This is what's going to drive the price increases. So we do see increasing more spreads in 2022, we're going to have that level of demand given where commodity prices commodity prices are likely to trade.
So I'm not concerned at all about that pricing is going to go up.
Alright, thanks very much.
Your next question comes from Keith Mackey from RBC Capital markets. Please go ahead. Your line is open.
Good morning, and thanks for taking my questions I, just wanted to start out by asking.
You talk about simulcast <unk> in the release and in the prepared remarks, just curious how much of that work Youre doing right now and can you just kind of run through maybe the margin accretion that you get from that from a simulcast <unk> job versus versus the standards for frac.
So we do simultaneously in both the northeast and in the Permian Basin and it can vary within the quarter. So we can have a situation where we're on Tucson will frac.
Jobs at the same time between the northeast and Texas, or new Mexico or that we're only on one so it's really hard to quantify within the quarter. It would be really difficult for me to give you anything that helps you understand that from a modeling standpoint.
But it does vary but it keeps us competitive and it's one of the reasons that our pricing is moving up and it's one of the reasons that we're able to activate more spreads.
It's hard for me to give you some numbers that would help you understand within the quarter, how that that looks within our numbers.
Okay understood.
And just curious now about the <unk>.
Pressure pumping market and consolidation and you mentioned that you expect pricing to be supportive just based on increasing levels of demand.
But do you think that there is.
Consolidation of our attrition needed to to help support pricing even further and.
Do you see much more of this happening or will it be just more more more natural attrition that helps.
The balance of the market as well.
Look we're always happy when we see consolidation within the markets that we compete in that's always supportive for the market and supported for pricing, but frankly going into 2022, we don't have to have any more consolidation for pricing to go up that's that's not something that has to happen pricing is going to go up because of the demand because of the tightness in.
The market today, if we get more consolidation in the market, that's great, but it's certainly not necessary.
Got it thanks very much.
Your next question comes from Waqar Syed from ETB capital markets. Please go ahead. Your line is open.
Thank you.
Sandy.
What's the horsepower that will be associated with the 12 crews that you're going to have active in Q1.
Hello, Wildcards. Thanks for asking me that question this morning.
Given that sometimes we're on Simon <unk> jobs, and sometimes we're not it really varies.
So.
I don't.
And this is across the northeast, Texas and in Texas, Its Permian South, Texas, So everything varies.
I'd have to get back to you on that with a number.
Okay.
55013, just like on average be a reasonable number.
I'm looking at my team over here.
It's going to be plus or minus in that range.
Little bit more when we're running simultaneously jobs.
And.
That 55 is not everything that would be on location, because you've got rotation of equipment back to the shop for maintenance.
Okay Fair enough and then Andy you mentioned about price increases and drilling let's take that first.
Could you maybe talk about the magnitude of the increases that have happened and what magnitude of increases you expect going forward.
So we don't normally call out a number but I'm going to call out a number today, because we're not going to put out any rigs unless the base price for the rig is in the low twenties, that's where we are and that's a significant step up from where we were a year ago or even in the summertime and that doesn't include any of the ancillary equipment that we might put on a rig.
<unk>.
Drill pipe other equipment. Other services, we may provide associated with contract drilling which drives that total price into the mid <unk>. So that's a big step up and really exciting that leading edge is now at that level in the low twenties.
<unk> spot rates in the spot rate and you have contracted right now in line, thus far has exceeded our contracted rate.
Spot, leading edge is above the contracted rate because we've been signing agreements over the last year and a half and even in this quarter and going into the fourth we have some <unk>.
Contracts that were signed pre COVID-19 that are starting to roll off so.
We have a variety of levels of pricing.
In that tower of contracts that we have.
But leading edges.
Moving up quickly so it's above where the average contracted prices.
Okay.
And then just shifting to the pumping side.
Any comments on the magnitude of price increases there, especially on the net price increases.
I'm going to call out our pumping team for doing a great job over the last few quarters.
They managed a hell of a downturn in state cash neutral during the Covid downturn and then here in 'twenty one they have provided.
Provided excellent service quality out in the field.
Being careful about how they've spent dollars whether its on opex or capex.
It's really paying off and showing the average adjusted EBITDA has been moving up nicely.
And so all of that combines when you look at the service quality providing the.
The new technology that we're putting out for some of the customers that helps push pricing, it's definitely in the double digit percentile movement upward quarter on quarter I know that doesn't mean much to say double digit percentile, but suffice it to say that we're pleased with the number.
Just one final question if I may.
EBITDA per tonne.
It was around $6 million annualized number in Q2, which is decent.
Decent when you compare it to the Pis.
But where do you think it could be like a year from now.
I think we're going to be back up in the numbers that reflect what I would say 2018, even early 19 before we started slowing activity in 2019 so.
I think theres still a lot of room for that to move because we see a lot of demand potential out there based on where commodity prices are whether it's oil or natural gas.
We see we see a lot of upside.
Thank you Andy I appreciate the answer.
Your next question comes from Jason <unk>.
From Coker Palmer. Please go ahead your line is open.
Hey, good morning, guys. Thank you for taking my questions.
Got it.
Good morning.
If you can help us just think about if you think about the pressure pumping capacity you have in terms of fleet, how many more idea on the sideline and then how should we think about capex required to get them back.
So we have around $1 6 million horsepower in total.
Well one three.
Just when you talk about the Frac horsepower, so and when you look at where we are today and where we'll be running up to 12 spreads, which we have visibility on now.
We still got a ways to go and like I mentioned earlier as you work into the existing equipment.
<unk> right now sure your Capex and Opex starts to move up in order to redeploy that equipment.
But we still have a ways to go we were running as many as 25 Frac spreads just a couple of years ago. So we still have all that inventory.
We will have all of that equipment in inventory, it's just a matter of looking at the economics, which we do on a project by project and case by case basis to determine if.
If we think it's economically feasible to reactivate.
Got it so you haven't had that at least in more fleets to go okay. That's helpful.
Coming back to you.
I'm going to drilling actually just thinking about.
Inflation is in the <unk> you are talking about day rates increasing.
Is it a way.
You can talk about when can we see the margins that we saw in <unk> is it more like a first half 'twenty can you just is it more second half one scenario. It's a first quarter 2022 scenario, we expect in the first quarter 'twenty two to rebound in the ballpark of where we were in Q3 of this year.
Got it and if I may squeeze in one more can you talk about demand and availability of five and half inch Joe Joe pipe, just like I was saying some anecdotally that.
E&ps are more willing to pay higher wildfire <unk> NGL pipe.
It is already sold out.
Yes, so five five inch drill pipe in.
Very short supply historically that was an offshore size and now we're using it in the U S onshore market.
That market has tightened up we own us a significant amount of $5 five which allows us to push pricing on the inventory that we have we have $5 five on order and we are hoping that the mills and the suppliers can keep up the mills are also having to.
Shift to produce more casing for the E&ps at the same time. So we'll just see how our deliveries go but we've been placing orders throughout this year for deliveries that will get into next year.
Okay.
Thank you for taking my questions.
As a reminder, if you'd like to ask a question. Please press star followed by the number one on your telephone keypad.
Your next question comes from Ian Macpherson from Piper Sandler. Please go ahead. Your line is open.
Thanks, very much for giving me a follow up I just wanted to see two things are you, hoping or expecting to close.
The well service.
Divestiture.
By year end.
And then also is going to ask if you have any framework for us for Capex for 2022, whether it's a range of numbers or just <unk>.
Ratable framework for activity.
Yeah, Hey, and this is Andy Smith.
<unk>.
We're engaged in a process right now on the sale of the production services business.
Don't really have a great estimate for when that will complete.
We're working actively currently.
And.
Within the next quarter over quarter after that I can't tell you exactly where it falls.
On Capex, it's too soon for us to give you that number we're going to look at it throughout.
The next few months as we're doing our budget process and we'll give you that on the fourth quarter call.
Okay.
Thanks.
Yes. Thank you thanks.
We have no further questions in queue I would like to turn the call over to Andy <unk> for closing remarks.
Thanks, Julianne well I'll say once again, we're really excited about what's happening in the business and the demand and pricing increases we are seeing going into 2022 and excited for the potential for this business next year. So thanks to all of the Patterson UTI team for everything that Theyre doing and thanks for those of you that joined us on the call today.
Ladies and gentlemen, this concludes today's conference call. Thank you for your participation you may now disconnect.
Okay.