Q3 2022 Patterson-UTI Energy Inc Earnings Call
Excuse me, ladies and gentlemen, this is the operator today's conference call is scheduled to begin momentarily.
Till that time your lines will be placed on music hold thank you for your patience.
[music].
Okay.
Good morning, My name is Dennis and I will be your conference operator today.
This time I would like to welcome everyone to the Patterson UTI energy third quarter 2022 earnings conference call.
Lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question and answer session.
If you would like to ask a question. During this time simply press Star then the number one on your telephone keypad to withdraw your question Press Star one again.
I would now like to turn the conference over to Mike <unk>, Vice President Investor Relations. Please go ahead.
Thank you Dennis good morning, and on behalf of Patterson UTI energy I'd like to welcome you to today's conference call to discuss results for the three months ended September 32022.
Participating in today's call will be 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.
These forward looking statements are subject to risks and uncertainties as disclosed in the company's SEC filings, which could cause company's actual results could differ materially.
Company undertakes no obligation to publicly update or revise any forward looking statement.
Statements made in this conference call include non-GAAP financial measures the required reconciliations to GAAP financial measures are included on our website, Pat energy Dot 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 Andy Hendricks for some opening remarks, Andy Thanks, Mike Good morning, and thank you for Joy.
As today for Patterson UTI, it's third quarter conference call.
I'm very pleased with our third quarter results as we continue to deliver growing profitability. We remain focused on generating returns on our invested capital while maintaining the high level of service quality and technology enhancements that customers expect from Patterson UTI.
As our profitability continues to improve we are increasing our forecast for 2022 consolidated adjusted EBITDA to more than $650 million.
Up from $600 million, we're also increasing our 2022 capex forecast to approximately $425 million up from the previous $390 million.
The increase includes the acceleration of rig upgrades for delivery in 2023, where this capex as being largely funded by customers.
We also had an opportunistic purchase of an additional tier for pressure pumping horsepower in order to continue to upgrade the quality and earnings power of our fleet.
Looking forward, we remain encouraged by our outlook and our potential to deliver free cash flow. We believe the industry is in the early stages of a multiyear up cycle, given the capital discipline and moderated growth of E&ps, which are temporary production increases in the U S.
We believe drilling activity continues to increase through next year, thereby driving increases in completion activity.
There's been a lot of discussion and reports in the industry over the last few months regarding what E&ps may or may not do with their drilling plans in the fourth quarter and next year.
As part of our 2023 planning process. We recently completed a survey of a large representative sample of our customers across each of our major businesses to better understand their drilling plans.
I believe you will find the results in lightning.
Our broad customer base represents a diverse cross section of the U S drilling and completions market ranging from the largest supermajors to public independents to small private operators.
Interestingly the more than 70 customers, we recently spoke with and who primarily drill and complete horizontal wells planned to add an additional 40 drilling rigs in the fourth quarter and almost 50 rigs in 2023.
We believe this is a good cross section of E&ps working in the U S and an indication of the activity strength in the U S market.
And while there has been a lot of discussion about what private e&ps will and won't do the ones. We spoke with plan to add a total of almost 20 rigs in the fourth quarter of 2022, and another 20 rigs in 2023 and.
And interestingly enough the increase by private E&ps is led by those backed by private equity.
In summary, based on recent commodity prices most of the customers. We had discussions with expect to add rigs through next year with no real discernible differences among the different classes of operators.
So turning now to my review of operations.
Again, I'm very proud of the solid execution at each of our businesses as we successfully increased both activity and pricing this quarter, while continuing to provide excellent customer service.
In contract drilling our average U S rig count for the third quarter increased by seven rigs to two 128 rigs as.
As of today, we have 131 active drilling rigs in the U S. Along with two additional rigs that are committed to return to work before the end of the year and four that are already contracted to be activated next year.
Across the industry pricing continues to grow as rig demand remains strong supply continues to be limited due to the dwindling availability of tier one super spec drilling rigs combined with the overall tight labor market and challenged supply chain.
Leading edge pricing for these rigs is approximately $40000 per day, including all ancillary services.
At Patterson UTI, we are taking advantage of the current strength in pricing by increasing the number of rigs under term contract.
Thereby improving our earnings visibility and reducing our earnings volatility.
During the third quarter, our U S contract drilling backlog increased by 61% to $710 million as we signed 27 term contracts, including three year contracts for five rigs with a major operator.
Our drilling business continues to have a leadership position and reduced emissions technologies, where our eco cell lithium battery hybrid solution combined with our automated engine management system has eliminated almost 700000 gallons of diesel consumption from drilling operations in the first three quarters of this year.
In the area of automation, our cortex operating system continues to be deployed in our drilling operations, which enables the functionality of key applications for improved drilling performance on our apex rigs.
Yes.
In pressure pumping, we saw consistent and repeatable execution across the various functions in our pressure pumping business from marketing to operations execution and support functions as well I would like to commend our team for what has been achieved we have increased our organizational efficiency and scale the business with a focus on reducing the overall cost structure.
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The benefits of this strategy were apparent in the third quarter, where we achieved historically high adjusted EBITDA per spread <unk>.
Additionally, we've been financially disciplined in terms of pressure pumping investments, which when combined with the strong cash flow generation from this business is driving very favorable financial returns.
We recently completed the opportunistic purchase of 35000 Frac horsepower with tier four engines. These pumps were previously used for lower pressure pumping down work and will allow us to upgrade existing spreads as well as a possibly activate a 13th frac spread in 2023.
Additionally, our pressure pumping business continues to invest in specific technologies to improve our services such as a new digital platform that will enhance field operations and our new eco start technology to further reduce emissions at the well site.
In directional drilling we remain focused on technology with many new developments to improve wellbore placement and quality.
With regards to the downhole tools used by our teams to steer the wells, we continue to benefit from the vertical integration of engineering key components for our performance drilling impact Motors and also our empower measurements and data transmission systems. This approach has improved our ability to drill wells faster and with better consistency and also to have better control of our costs in <unk>.
Apply chain.
Additionally, our well placement data analytics business superior QC continues to lead the industry in improving horizontal well placement accuracy and quality.
Utilizing proprietary survey correction algorithms a recent third party validation process show that superior QC data analytics calculations are approximately three times more accurate than standard industry algorithms for well placement, allowing for greater precision and the placement of the horizontal section of our customers' wells.
With that I will now turn the call over to Andy Smith, who will review the financial results for the third quarter.
Thanks, and good morning.
As Andy said, we are pleased with our third quarter results, where we again achieved improved revenues and margins across all of our segments.
Net income for the third quarter was $61 $5 million 28 per share up from $21 $9 million or <unk> 10 per share in the second quarter.
In contract drilling revenues and margins increased significantly in the third quarter due to continued day rate pricing momentum contract renewals and increasing activity.
In the U S. Our average adjusted rig margin per day increased by $1080 from the second quarter to $10 $470.
Average rig revenue per day increased by 2000 and $770 as day rates continue to strengthen and we benefit from contract renewals with more favorable pricing.
Average rig operating cost per day increased by $1690 during the third quarter due to general inflationary pressures, including wage increases for both rig based and support personnel as well as general cost inflation for repairs and maintenance.
At September 30th 2022, we had term contracts for drilling rigs in the U S providing for approximately $710 million of future day rate drilling revenue.
From approximately $440 million at the end of the second quarter.
Based on contracts currently in place in the U S. We expect an average of 81 rigs operating under term contracts during the fourth quarter at an average of 56 rigs operating under term contracts over the four quarters ending September 32023.
In Colombia third quarter contract drilling revenues were $18 $7 million and adjusted gross margin was $5 $8 million.
For the fourth quarter, we expect our average rig count in the U S to increase by four rigs to 132 rigs average adjusted rig margin per day is expected to increase approximately $1500 to almost $12000 per day, driven by an increase in average rig revenue per day.
In Colombia, we expect a seasonal slowdown in the fourth quarter as such we expect to generate approximately $12 $7 million of contract drilling revenue in Colombia with adjusted gross margin of approximately $3 $7 million.
In pressure pumping revenues and margins improved during the third quarter as our active spreads were highly utilized and we obtained better customer pricing.
Pressure pumping revenues increased 21% sequentially to $288 million and adjusted gross margin increased 62% sequentially to $76 million.
For the fourth quarter, we expect higher downtime due to the holidays.
As such pressure pumping revenue is expected to decrease to $270 million and adjusted gross margin is expected to be $62 million. We then expect revenues and margins to rebound in the first quarter.
In directional drilling during the third quarter increased pricing and activity resulted in sequentially higher revenues and margins.
Directional drilling revenues improved to $58 $9 million and adjusted gross margin improved to $10 $4 million.
For the fourth quarter, we expect incremental pricing gains with activity levels slightly higher than the third quarter.
As such we see fourth quarter revenue improving to $61 million.
<unk> gross margin is expected to grow to approximately $11 million.
And our other operations, which includes our rental technology and E&P businesses revenues for the third quarter improved to $24 $9 million and adjusted gross margin improved to $11 5 million.
For the fourth quarter, we expect both revenues and adjusted gross margin in our other operations to be similar to third quarter levels.
On a consolidated basis, we expect total depreciation depletion amortization and impairment expense to be approximately $121 million for the fourth quarter.
Selling general and administrative expense for the fourth quarter is expected to be approximately $29 million.
Not expect a meaningful tax amount of tax expense or cash taxes for 2022.
With that I'll now turn the call back to Andy Hendricks. Thanks.
Thanks, Andy as I've mentioned at recent conferences, one of the challenges that oilfield service companies have had in producing strong returns during previous cycles over the last decade was it most of these cycles work of a sufficient enough duration to allow service providers. The time, that's required to raise pricing across their full portfolio of services and customers.
This is in contrast to an E&P, which outside of hedges in contracts has a real time mark to market for the price of their product.
I am very pleased with the progress that is reflected in our third quarter results and I'm encouraged by our outlook for a multiyear up cycle.
Our teams did a great job continuing to push pricing across all service lines and going into next year, we expect to see further pricing increases as many of our existing contracts rollover, especially in contract drilling.
As such I believe we still have significant upside to our current margins and free cash flow.
Our expectation is based on our discussions with our customers, which yielded very interesting results from a recent customer survey.
While there may be a limited number of e&ps dropping rigs. The net result is a rig count that will continue to increase in Q4 and in 2023.
And while I have heard anecdotal stories of private e&ps dropping rigs in Q4, a review of our customers doesn't show this to be the case.
Therefore based on our positive outlook, we have been discussing how best to return our free cash to our shareholders and also how best to describe our intentions.
At Patterson UTI, we have a strong history of returning cash to shareholders as we've returned more than $1 billion since 2012 through dividends and share buybacks.
And considering how best to return cash to shareholders going forward, we considered the following points.
First we expect that the contract drilling industry will be much less capital intensive than prior cycles.
As the major retooling of our drilling rig fleet to AC powered high spec and Super spec rigs is complete.
Second and as we've discussed we are encouraged by the prospect that this cycle has the strong potential to be a multiyear up cycle.
And lastly, our strong balance sheet, and our increasing cash flow visibility from term contracts have Patterson UTI well positioned to continue returning capital to shareholders.
Therefore, as we look forward, we will target to return 50% of free cash flow defined as cash provided by operating activities less capital expenditures to shareholders through dividends and buybacks.
As such I am pleased to announce that our board of directors declared a quarterly cash dividend on our common stock of <unk> <unk> per share to be paid on December 15, 2022 to holders of record as of December one 2022, which.
Which represents a doubling of our prior quarterly cash dividend.
We're also announcing that our board of directors has improved an increase to our authorization for share buybacks were from this point forward, we are authorized to buy back $300 million of shares.
We are excited at the prospects for Patterson UTI shareholders with the potential for returns going forward.
With that we would like to thank all of our employees for their hard work efforts and successes to help provide the world with oil and gas for the products that make people's lives better.
Dennis we'd like to open the call for questions.
At this time I would like to remind everyone in order to ask a question simply press Star then the number one on your telephone keypad.
Your first question is from the line of Scott Gruber with Citi. Please go ahead.
Yes, good morning.
Morning morning.
Really appreciate the color on the survey Andy just given that debate.
Love to see it obviously I guess, one concern that yes.
Such servings.
This.
Yes, there is an incentive for customers to tell you it appears that way.
Rig adds are forthcoming, which motivate you to take steps to reactivate rigs and obviously there is a.
A long lead time on some items today.
And so how do you think about kind of going out and.
Kind of validating the survey.
I guess your rig count is up in <unk>, which is supportive but anything you could speak to in terms of kind of other confirmatory data points that provide confidence to you that the 23 growth materialize.
So I mean these are direct discussions with our customers who are teams work with every day. So this is not something that I feel like requires any further value validation now one thing to keep in mind is that these arent approved budgets, yet because e&ps are still working through their budget process and may not final.
That till early next year, but these are based on the direct feedback from the teams at the E&ps, who are having to plan for what's going to happen next even before approval comes through so I'm comfortable with these numbers, but the thing you have to remember is we're talking to customers who are drilling horizontal wells they are using <unk>.
Tier one super spec drilling rigs.
This is a subset of the overall total rig count in the U S. I think last time I look there was still 140 mechanical rigs in the total U S rig count and Thats not a part of the sector that we do anything with those that rig count there can move up and down itself, but based on what we're hearing our customers and especially the privates.
Are not slowing down their progress and we didn't see any discernible difference as I mentioned between the different classes of operators in terms of who is picking up rigs.
From now until the end of next year.
Got it thats.
Very encouraging.
And then can you talk about Capex.
Capex.
For next year.
There's no budget today, but just some of the major items obviously.
A major peer of yours has talked about maintenance being up kind of in the $1 2 million kind of per rig range.
The arrangement that we should think about the Patterson and then any early color on.
Upgrades the number for you next year prospectively or a range in there.
Cost per upgrade that we should think about and then any early thoughts on some of the ancillary spending on <unk> and other items.
Yeah, Hey, Scott This is Andy Smith.
Look we again, we haven't gone through our budget process yet.
But we do we have asked our guys and leads with chronic looked around the company in <unk>.
Taken a thought or taken a look at 2023 capex.
So I think that's probably the easiest way to sort of frame. It is if you look at.
2022, and our guidance of $425 million maintenance capital, obviously with activity going up is going to be a little higher we are seeing a little bit of inflation in maintenance.
We're looking at annual maintenance capital per rig now about $1 million per rig.
But so if you start with that 425, you think of some incremental adds for for activity as well as some inflation on maintenance capital and then if you think about the upgrades, which we've already announced the five rigs that are under three year contracts.
Upgrades were pre funded by customers. So we receive the cash in the third and fourth quarter of this year, but that capex from an accounting standpoint will hit next year.
So that's about $35 million to add to that number. So if you think about that plus kind of where we ended up this year.
Now all in I think the number totals.
Right around the $500 million range, plus or minus $500 million. So so that's kind of the number that we're targeting at this point.
Okay I appreciate the color I'll turn it back thank you.
Thanks. Thanks.
Your next question is from the line of Luke Lemoine with Piper Sandler. Please go ahead.
Hey, good morning.
Andy you had a breakout quarter in your pressure pumping results can you talk a little bit about how you see this progressing past <unk> either on a gross margin basis or GP per fleet.
Well, let me kind of describe it more in relative standpoint so.
As we get into Q4.
We see a little more white space in the calendar and we've had a lot of discussions about whats really driving this.
Is it budget can see what else is going on and really it's not so much budget fatigue for our customers and pressure. Upon me, it's really that things have been so efficient, we're starting to bump up against the drilling rigs and so.
We're seeing some white space in the fourth quarter and I think in the industry in general that may be happening as well because I hear a number of comments about the efficiencies and pumping operation, but I think as the drilling rig count will continue to increase going forward that that will help alleviate that but what it means is essentially there is probably no.
A real ducks out there because the pumping spreads are close to the drilling activity.
Then going forward in <unk>.
In Q1, I expect our pumping results to move back towards what we saw in Q3.
Caveat of cold winter in the Permian Basin in New Mexico, which can slow operations, sometimes in January so.
While we're seeing some white space in the fourth quarter I think that starts to disappear in the first quarter and the results get closer back to where we were in the third quarter of this year does that makes sense.
Yes, yes, absolutely kind of maybe looking more during the <unk>.
Better weather months at 23, two Q3, Q I mean, it seems like there's potential upside from <unk> 22 results is that fair.
Yes, that's fair.
Okay got holidays at the end of this quarter.
But then we get a little bit of a winter in January sometimes February and Permian and then things start to improve from a weather standpoint.
There is no reason why we can't duplicate what we've done in Q3 outside of those circumstances.
And then.
On your rig survey with your customers those incremental add sure you were talking about.
This all Super spec rig adds were just <unk>.
When faced with our spectrum, how would you characterize that.
In General. These are these are our customers who are looking to add super spec class rigs.
Okay got it thanks, so much.
And again this was our customer base across our drilling business, our pressure pumping business, our directional business our rental business we.
With broadly across our entire customer base for the company.
Your next question is from the line of Derek <unk> with Barclays. Please go ahead.
Hey, good morning, guys I just wanted to stay on that survey. So those 90 rigs added through 2023, I'm wondering what does that imply to you as far as total rig adds for the market and then have those 90, how much share do you do you expect to get in your rig additions and then of those races, greggs that youre going to add what's the <unk>.
A lot of Capex, our capex upgrades required I know you broke it out for us in those first 34 rigs in the next 30, just an update on where you are there and the dollar per rate cost to get those rigs deployed.
Yes. So this was this was a sample of our customer base. So a subset. So when you total it up there is the potential for more rig adds and what we were just describing because this was a little over 70 customers that we've talked to and gather data from so there is potential for more rigs to be added in that.
When we look at ourselves and what we will likely do with various customers and what we will likely do in terms of reactivation and some upgrades or rig count add in 2023 is probably in that 15 to 20 rig range and then Andy gave you some color on what we're expecting in the <unk>.
Capex for different reasons in that plus or minus $500 million and thats.
That's a high level look at it for 'twenty three as we haven't gone through the budget process, yet, but that gives you some idea of that total.
Got it that's helpful.
Turning over to pressure pumping I know you just ran through your expectations as far as where EBITDA per fleet can trend by the end of this year into next but could you break it down another level for US can you talk about the differences in utilization and pricing in vertical integration. Obviously this is a historic mark for you guys and setting a new floor and profitability, but what has really.
Driven that between those three buckets of utilization pricing vertical vertical integration as we think about from now through the end of next year.
Yes.
As I've said, it's really across the organization in pressure pumping from the marketing teams.
Pushing pricing and keeping the pricing up at the towards the leading edge levels, where we can where we have that ability in our agreements.
The operational efficiency that we're seeing from the operations in the field, where we're just getting more stages per week per month per quarter and.
The operation support to make sure that maintenance is done and we have pumps that work and we have lenders at work and so.
The business is running really well these days and we're just really pleased with the overall successes there.
Okay very helpful I'll turn it back.
Your next question is from the line of Don Crist with Johnson Rice. Please go ahead.
Morning, gentlemen, how are you.
Yes, Don how are you good.
Good.
On your term contracts.
<unk> you just under 30% termed out for the next 12 months or so.
What is your just general thoughts on where you can push that too or do you have any.
Expectations of getting above 50%, there just general thoughts around term contracts going forward.
You know as we as we came out of this bottom of the cycle, we were keeping any agreements and contract.
Terms very short because we knew we had upside in pricing and as we have.
Begin to push pricing up which this year pricing has moved faster than probably ever has historically in our industry.
And so.
We were reluctant to start signing in and layering in longer term contracts until.
We can push pricing as much as we could but like an investment portfolio. We have a long term view of this and so we started layering in term contracts.
The portfolio of contracts that we have in signing up longer ones.
August we sign the five rigs for three years, but we signed other terms in the year to year and a half.
Even up to two years for some so we've got a blend right now and as we continue to see leading edge rates move up next year, which I think they will probably layer in some more as well, but we're measured in that process, we still want to be able to capture the upside but at the same time, we do think it's prudent from time to time when.
It makes sense for the right customer and the right projects to sign a long term contract.
I appreciate the color there and one more for me.
Fly chain, obviously was super tight early in this year. It seems like it's loosening. Some can you just give us general thoughts on on the supply chain.
How thats progressed through the year or is it much better now we're a little bit better now than it was earlier this year.
I would say supply chain is still tight and that's still one of the constraining factors in growth and Thats whats keeping the rig market tie in the pressure pumping market tight supply chain is still tight what's I think has evolved is how we've had to manage that where we modified the planned six months to nine months ahead to get certain.
Now we are planning a year ahead to get certain things and so it's really an adjustment on our side on how we manage the supply chain, but it is still tight.
I appreciate the color I'll turn it back thanks.
Thanks.
Your next question is from the line of <unk> <unk> with Bank of America. Please go ahead.
Hi, Hi, Andy and Andy Thanks for taking the question.
Sorry to beat it on R&D on the Sony Thank you, but I think it's important so let me ask another one on that one.
Obviously commodity prices have been really one September .
September , especially we saw that.
<unk> go into the low seventies, I think 70 273. So if you can help us on when the facility was got it out.
Do you think commodity price.
As getting E&ps are not getting E&P, just give us some context on that and radio thing sensitivity lies.
Why do you think oil prices might have going forward. Additionally, revisit that plan.
Yes.
All of these discussions with customers were happening towards the end of September and early October to give you that timeframe of what commodity prices were doing at that time, but I can tell you. The commodity prices have had the movement in commodity prices have had no effect on any of our customers plans there.
It just hasnt been enough.
Movement to cause anybody to rethink what they are doing and we've even had those discussions.
To double check and we've seen some downward movement in commodity prices over the last few months, but even that downward movement wasn't enough to change plans or any customers that we had.
Okay. Okay.
Good deal.
Correct.
And then one thing right.
Last week when you come to you I think in fact, the only company that has a big footprint on both the drilling and the pressure pumping side right and I think both of those markets are clearly risks.
You were to compare and contrast.
Two markets between rigs and Fac, which one do you think it's more attractive for you to deploy more capital going forward.
We find both of these businesses attractive and they.
Their level of attractiveness kind of changes at different points in the cycle. If you look back to 2021, and our Frac business starting to grow and pricing started to move up faster earlier than the drilling business, probably by about six months and.
We still see some upside in pressure pumping pricing as we get into next year, but drilling.
It's about was lagging about six months behind that cycle on pressure pumping, but we're very pleased with how both of these businesses are performing we are pleased with the returns in both of these businesses the amount of free cash flow we're getting.
Okay, Awesome and a quick one on cash taxes I think.
You've talked about that in 2022, no meaningful cash taxes, how should we think about 2022.
Great.
Yes, I wouldn't expect that we're going to have a lot of cash taxes, we'll give better guidance on the next call.
We may have some small amounts in 2022, and 2023 related to both Colombia or a little bit in Colombia, but more state, but generally on a federal state from a federal standpoint, we shouldn't have a lot of cash taxes.
Okay, perfect antitank for that I've done it back.
Thanks.
Your next question is from the line of Keith Mackey with RBC. Please go ahead.
Hi, good morning, and thanks for taking my questions just wanted to start out on drilling Opex. It's certainly has moved higher across the industry now around 18000, a day hasnt moved as much as as rates, obviously, but with more longer term contracts signed.
Can you just talk about how insulated you might be against future increases and what you think is driving the the increase in the labor Opex and will that will that continue.
So over the last year, we've had to give to pay raises and.
In the field operations, whether it's for drilling pressure pumping et cetera here at Patterson UTI.
The first pay increase we gave which was about a year ago was really an adjustment for the market because and especially in drilling we have not been able to give our teams pay raises since the downturn of 2015, and so we were able to give one pay raise about a year ago.
And then the second one we did was really more of a cost of living adjustment as well too.
To factor in the inflation that we're seeing here in the U S and so those those two have happened recently.
I don't anticipate any broad changes in that going forward, but there's other things happening as well, we're seeing lubricant prices move up we're seeing some other things move up so there is a little bit of inflation still happening now one thing to remember as well is when you are looking at our cost per day and drilling that's a fully loaded <unk>.
Cost per day for that business, which includes.
R&D that includes other things that others may not included in that number, but it's fully fully loaded burdened from from an engineering and operations standpoint for that business.
Got it thanks for that and maybe just shifting to the pressure pumping the acquisition of of the horsepower.
Do you see there being more or do you see opportunities to do more of that type of stuff and maybe if you could just talk about.
Any metrics you can give around say, what what you might have paid for that versus what it would cost to have to have acquired debt acquired that that horsepower on a.
If it were new kind of thing.
So this was kind of an unusual opportunity that came up where there was a relatively small business in west Texas in the Permian that had relatively new equipment, but it was only being used for low pressure pump down so it wasn't really seeing it.
Any type of harsh used that we would typically using the frac business and so it just so happened that these pumps were available.
But yes, they did have hours on them, but it was relatively soft the hours compared to what we do so we were real pleased with the condition of the equipment and.
I'm not going to get into any numbers, but we did get a significant discount off of buying new equipment. So we were able to pick up tier four equipment now with that equipment will very likely end up working most of that into the existing fleet.
We can take these tier fours, we can add upgrade kits to add dual fuel to some of these and so we will continue to upgrade.
What we're offering in the market and also the earnings power of our existing spreads.
Got it appreciate the comments thanks very much.
Your next question is from the line of Sean Mitchell with Daniel Energy. Please go ahead.
Good morning, guys and thanks for taking the question.
Just and thank you for the color around your survey.
Very helpful.
When you think about 'twenty three can you rank, where you see the greatest demand from your customers or the incremental demand youre seeing in the form of the survey or otherwise is it Permian haynesville Marcellus or give us any color around are you seeing more demand from one basin or the other.
We're seeing.
We went through this the other day just to double check, but we're seeing growth in all the basins, some more than others or even seeing rig adds in the Marcellus Utica.
But primarily it's going to be Permian midcon little bit of the Bakken as well, but we are seeing the.
Rig count increases in all of the basin.
Okay.
And then maybe a follow up just as we've listened to the call. So far lots of oil service companies highlighting what international it looks like in 'twenty. Three I know you have rigs in Colombia is there any.
Opportunities outside of Columbia that you guys are thinking about.
Well the Columbia business is doing really well for us really pleased with how that team is running that business and their performance and execution that they have down there.
Team has a great reputation and it may give us an opportunity in the future to expand next door or into Ecuador, but we'll just have to wait and see how that plays out.
Got it thanks guys.
Thanks.
Once again every one of you would like to ask a question. Please press Star then the number one on your telephone keypad.
Your next question is from the line of David Smith with Pickering Energy Partners. Please go ahead.
Hey, good morning, and thank you for taking my question.
Good morning.
Wanted to circle back to the.
The comment about leading edge lower 48 rates at 40000, a day, including ancillary services.
Could you please remind us where you see average ancillary services or Alternatively, how would you how you would characterize leading edge based pricing relative to the update you gave us three months ago.
Yes, it's still been moving up and I expect it to continue to do.
Right now, we're seeing it around plus or minus $40000 per day at the leading edge include.
Including drill pipe any extra crew and E&P may want including forklifts light plants.
All of the ancillary type services that we may provide.
Rig moves et cetera, but.
When you.
Average it all out you are at that plus or minus 40000, but where the rig count for horizontal rigs continuing to move up into next year and through next year.
Still some more upward movement on that number.
Okay.
Got that.
Do I remember correctly, you are running about seven gas burning fleet out of the 12.
Yes, 77 of the Frac spreads that we run are primarily natural gas.
Just building on your comment about integrating that opportunistic purchase that entered the fleet with some.
Some dual fuel conversion, how do you think about the cadence of converting the remainder of your fleet.
Yeah.
Didn't know if you might be expecting more opportunistic acquisition.
Yes that might allow you know retirement of old.
The horsepower.
Any thoughts on what Youre seeing currently for pricing.
Tier two diesel legacy equipment versus.
Our formula for you all.
So we're still seeing the overall frac market tied with the exception of a little bit of white space here in the fourth quarter, but it'll stay tight next year.
We do get a premium for running tier four dual fuel and so this was a nice little tuck in for us to be able to do but it was a bit unique I'm not sure. There's really many others out there like this but.
But we were pleased to be able to do this and it allow us to do some more conversions and then either.
Increasing pricing with whoever is going to be running that frac spread when we do that but it's not really a cadence.
I would describe it I would just describe it as an opportunity to be able to.
Some tier four pumps and work it into our system in and pushed the margin where we can.
Right.
Okay. That's it for me thank you very much.
Your next question comes from the line of Dan Kutz with Morgan Stanley . Please go ahead.
Hey, Thanks, good morning, guys.
Morning, Joe.
Just wanted to follow up and confirm something on kind of tracking in line of questioning.
Am I still understanding correctly that there's not really any plans contemplated beyond this potential 13th fleet to reactivate any of that equipment.
Could you see a scenario, where you were taking some of that.
Idle equipment that you have in investing in some upgrades and putting anything.
Beyond that potential 13 fleet next year.
So right now we're working 12.
And our current view is that we will continue working 12, we haven't spent much time to decide whether or not we would activate number 13 yet.
Adding these pumps gives us more flexibility to do that with.
Tier four type equipment, but we haven't made that decision so.
We'll work through that over the next few months.
We continue to evaluate again, we were getting into white space in the fourth quarter. So there was no point in trying to do something in the fourth quarter, We may do something in 'twenty three but.
We just haven't decided our primary focus right now is returning cash to shareholders. We've got a new commitment out there to return 50% of our free cash flow.
That is that's our focus so we're also trying to manage the capex versus the EBITDA to make sure that we're maximizing what we can return to shareholders.
Great. Thanks.
Maybe just staying on the shareholder returns.
So.
I wanted to just clarify how you guys are thinking about hitting that.
50% of free cash flow target, if I'm just looking at it.
EBITDA for 2023 is around 900 million, maybe that's conservative.
That doesn't assume a lot of growth beyond your <unk> Guide and then if we back out the capex.
That the 500 that you spoke to you that gets to about 400 million so 50% of that.
And it seems like there's about $70 million next year as is the flywheel.
The buybacks.
To kind of hit that.
The same target.
The potential for dividend, increasing as a special dividend just wanted to.
Get a little bit more clarity on the strategy.
Yeah.
I think all options are on the table.
<unk> described what our incentives with the dividend, where we're really pleased that we've been able to double it now going forward. So that has that will be roughly 70 $172 million a year in cost to be able to do that.
Out of that free cash flow and then we'll try to look at the rest with share buybacks, but all options are on the table.
Understood. Thanks, that's helpful I'll turn it back.
Thanks.
This concludes the Q&A portion of today's call I will now turn the call back to Andy Hendrix for any closing remarks.
Thanks, Dennis I, just want to thank everybody that joined the call today. We appreciate the questions and again I'd like to thank all the employees of Patterson UTI for the great work that Youre doing thanks a lot.
This does conclude the Patterson UTI energy third quarter 2022 earnings conference call. Thank you for your participation you may now disconnect.
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Okay.
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Sure.