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Patterson-UTI Energy Inc
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Thank you for standing by. At this time, I would like to welcome everyone to the Patterson-UTI Energy Second Quarter 2023 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remark, there will be a question-and-answer session. [Operator Instructions] Thank you.
Mike Drickamer, Vice President of Events to Relations. You may begin your conference.
Thank you, Cheryl. Good morning. And on behalf of Patterson-UTI Energy, I'd like to welcome you to today's conference call to discuss the results for the three months ended June 30, 2023. Participating in today's call will be Andy Hendricks, Chief Executive Officer; Andy Smith, Chief Financial Officer; and Mike Holcomb, Chief Operating Officer.
A quick reminder that statements made in this conference call that state the Company's or management's plans, intentions, targets, 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 should cause the Company's actual results to differ materially.
The Company undertakes no obligation to publicly update or revise any forward-looking statements. Statements made in this conference call include non-GAAP financial measures. Required reconciliations to GAAP financial measures are included on our website, patenergy.com and in the Company's press release issued prior to this conference call.
And now, it is my pleasure to turn the call over to Andy Hendricks for some opening remarks. Andy?
Thanks Mike. Good morning, and welcome to Patterson-UTI's second quarter conference call. Our drilling business performed very well with sequential increases in both revenues and margins. Contract renewals favorably impacted our average revenue and adjusted margin on a per day basis, offsetting the slight decline in our rig count.
The improvement in contract drilling revenues and margin during the second quarter met our expectation and our rig count outperformed the broader industry decrease. The decline in industry activity had a more significant impact on our pressure pumping business with volatility and white space impacting results.
The commodity price volatility in June led to some customers deciding to reduce drilling and/or completion activity. For us, the decrease in frac activity occurred much faster than the decrease in our rig count. And as such, we believe our pressure pumping activity has already reached a trough here in July, while we expect additional rig releases over the next few weeks.
With the recent strength in oil prices along with natural gas futures in contango, we believe the industry rig count is near bottom, and both rig count and frac activity will improve later in the year and in 2024.
In contract drilling, we ended the second quarter with 127 active rigs and expect a reduction of approximately 10 rigs during the third quarter, of which six have already been released and two more are expected to occur within the next week. These leases are the result of notifications received primarily in late June.
Following these near-term rig releases, we expect our rig count to stabilize and are optimistic that the recent strength in oil prices may positively impact future drilling activity. Despite recent rig releases, day rates remained strong with recent contract renewals for super-spec rigs in the low to mid-30s, including ancillary revenue. As previously discussed, we continue to prioritize margins over activity.
In Pressure Pumping, we believe the decline in activity is already behind us, and we have additional work scheduled to begin later this quarter. Based on current activity levels, we stacked the Tier 2 diesel spread in order to accelerate its conversion to a Tier 4 dual fuel.
When this conversion is complete, 10 of our 12 spreads will be dual-fuel capable including four spreads that will be Tier 4 dual fuel, which better positions us to take advantage of what we expect to be increasing completion activity later in the year and in 2024. Pressure pumping pricing has been challenged recently given the decrease in activity, but the market pricing for dedicated work has held up better than spot work.
With that, I'll turn the call over to Andy Smith, who will review the financial results for the second quarter.
Thanks, Andy. Net income for the second quarter was $84.6 million or $0.40 per share, which included $7.9 million of merger and integration expense and $3.8 million of impairment expense in our E&P business.
During the second quarter, we repurchased 1.8 million shares, which brings the total repurchases under our share repurchase program through the first half of the year to 7.4 million shares or approximately 3.5% of the shares that were outstanding at the beginning of the year. Including $33.5 million of dividends, we have returned approximately $126 million of cash to our shareholders through the first six months of 2023.
At June 30, $281 million remained under our share repurchase authorization, however, our ability to repurchase shares during the third quarter may be limited due to the pending merger with NexTier. We remain committed to targeting a return of 50% of free cash flow to shareholders through a combination of dividends and buybacks. For the first half of 2023, we are well ahead of this target as we opportunistically repurchased shares during the first quarter.
Based on our outlook for the second half of the year, we are lowering our 2023 CapEx forecast of $485 million. This forecast is comprised of approximately $280 million of CapEx for contract drilling $140 million for pressure pumping, $20 million for directional drilling and $45 million for our other businesses and general corporate purposes.
In contract drilling, average adjusted rig margin per day in the U.S. increased $1,030 sequentially to $16,910, driven by a $1,190 increase in average rig revenue per day to $35,940. At June 30, 2023, we had term contracts for drilling rigs in the U.S., providing for approximately $760 million of future day rate drilling revenue. Based on contracts currently in place in the U.S., we expect an average of 71 rigs operating under term contracts during the third quarter of 2023 and an average of 44 rigs operating under term contracts over the four quarters ending June 30, 2024.
In Colombia, second quarter contract drilling revenues were $12.9 million, with an adjusted gross margin of $3.7 million. For the third quarter in the U.S., we expect our average rig count will be 119 rigs. Average rig revenue per day is expected to be approximately $35,500 and average rig operating cost per day is expected to be $19,400 which reflects a slight increase in operating costs associated with the number of rigs being stacked this quarter. In Colombia, we expect to generate approximately $8.4 million of contract drilling revenue during the third quarter with adjusted gross margin of approximately $2 million.
In pressure pumping, during the second quarter, increased white space in the calendar and lower pricing on primarily spot market work contributed to a sequential decrease in revenues and margins. Second quarter pressure pumping revenues were $250 million with an adjusted gross margin of $53.8 million, for the third quarter, we plan to operate 11 spreads, we have had substantial white space in July, but we expect improving utilization through the remainder of the quarter. Maintaining enough crews for the increasing work will negatively impact margins in the third quarter. Accordingly, for the third quarter, pressure pumping revenues are expected to be approximately $230 million with an adjusted gross margin of $37 million.
In our Directional Drilling segment, we experienced a decline in revenue and margin during the second quarter due primarily to reduced activity levels. Directional Drilling revenues were $55.1 million in the second quarter with an adjusted gross margin of $7.8 million. For the third quarter, we expect directional drilling revenues to decrease to $52 million, although expected adjusted gross margin is expected to be approximately flat with the second quarter.
In our other operations, which include our rental, technology and E&P businesses, revenues for the second quarter were $21.1 million with an adjusted gross margin of $8.3 million. For the third quarter, we expect revenues and adjusted gross margin to be similar to the second quarter.
On a consolidated basis, in the second quarter, the total depreciation, depletion, amortization and impairment expense amounted to $127 million, including $3.8 million of impairment charges at our E&P business. For the third quarter, we expect total depreciation, depletion, amortization and impairment expense of approximately $122 million.
Selling, general and administrative expense for the third quarter is expected to be approximately $31 million. Our effective tax rate for 2023 is expected to be approximately 17% although we do not expect to pay any significant U.S. federal cash taxes.
With that, I'll now turn the call back to Andy Hendricks.
Thanks, Andy. Looking ahead, we are constructive on the overall U.S. onshore market. With WTI trading above $75 and natural gas futures about $3.50 in forward months, E&P operators should see significant improvement in their well economics. We expect that some operators will increase their activity in drilling and completions by year-end and into 2024.
As 2025 is planned to be a big year for LNG export, we expect to see activity in gas basins recover in 2024 to previous levels or higher. With the increasing activity in the gas markets, we expect overall utilization and pricing to improve into next year across the U.S.
The U.S. onshore market is poised to remain steady and strong for the foreseeable future. Also, we are very excited about the recent announced transactions to strengthen our position as a leading provider of drilling and completion services in the United States. The merger with NexTier will bring together two top-tier and technology-driven drilling and well completions businesses, creating a leading platform at the forefront of innovation.
Similarly, Ulterra's leading position in the PDC drill bit business will expand our operational and technology platform, expand our data portfolio and broaden our geographic footprint through strong relationships with key international customers, especially in the Middle East.
We continue to work toward closing these transactions and look forward to welcoming employees from both NexTier and Ulterra to the Patterson-UTI team. With that, we'd 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.
Cheryl, we'd now like to open the call to questions.
[Operator Instructions] Your first question is from Arun Jayaram of JPMorgan. Please go ahead. Your line is open.
Andy, you guys have been able to kind of hold -- leading end of day rates at attractive levels. You mentioned low to mid-30s. As we think about 2024, what's your confidence in being able to hold those types of day rates as we start thinking about kind of fine-tuning our model for next year?
As we mentioned before, and Good morning Arun, as we mentioned before, we're really focused on trying to maintain day rates and margins, not focused on the market share, things have gotten a little bit more competitive recently when you're not on term contract. And we decided we don't want to fight all these, and our rig count is going to go down a little bit, but this is more of a softness hat we see improving later in the year and certainly going into next year.
But it's our objective to try to maintain pricing where we can. And when you look at the leading edge down into maybe low 30s to mid-30s, and that's including everything. It really hasn't come down that much. Let me hand it over to Mike Holcomb, we'll have some more comments on that, too.
I think the thing that I would add is, I mean, for us, leading edge this quarter is met renewals with existing customers and clients. And there's probably some work out in the market. It's a bit more competitive than that. But if you think about it looking forward, commodity prices stay in the more recent range going forward then we're very confident that pricing is going to be stable with some upside as we move into the next year. I think there, it really depends on.
[Audio Gap]
How many oil rigs do you think we could recover next year?
I don't think I know exactly what the number is going to go to next year. But you look at where the Baker Hughes rig count is now where it was earlier in the year, you get a recovery in gas, you're probably pushing over 700 rigs in the first quarter next year. But I think it just has upside from where we are.
Okay. I know that was a tough one, but I was curious on your thoughts. Thanks Andy.
Your next question is from Kurt Hallead of Benchmark. Please go ahead. Your line is open.
Appreciate the color commentary as always and the perspectives on the outlook. So Andy, in the context of the land drilling market, it appears to me that the pricing dynamics have stabilized, and I think you referenced kind of low 30s to mid-30s. But is there any incremental -- a couple of your peers have talked about maybe some incremental slippage in cash margin and some kind of rigs re-priced that might have been priced at a higher level, kind of coming back into the current market elements. When you think about your rig fleet, is everything that you've kind of booked out for the rest of this year kind of solidly in that 32% to 35% range? Or do you see some slippage on cash margin going into the fourth quarter?
I think right now, it's going to be pretty steady. I think we'll have to wait and see how fourth quarter plays out and what the rig count does towards the end of the fourth quarter.
Okay. And then just a follow-up in the context of the frac market as you add, you go from 11 crews to 12 crews a year in the fourth quarter. If you run the math on the revenue per crew that you expect in the third quarter, extrapolate that into the fourth, it looks like your fourth quarter revenue could approach second quarter levels. But logically, to me, that doesn't seem to make sense given the market dynamics. So how should we think about the frac revenue progression going out again into fourth quarter?
I think -- let me just kind of explain what happened in Q2 and what we're seeing so far in Q3, and it's really about towards the end of Q2, we had an acceleration in white space and we're starting off in July with a lot of white space in the calendar in pressure pumping, and it only warrants us working 11 spreads in the quarter. But we're seeing more dedicated work layering in at the end of the third quarter, and so it makes sense to have that 12 spread working in the fourth.
So, we're carrying some extra costs in the third within the schedule starts to round out a lot more towards the end of the third quarter and going into the fourth quarter with much less white space. So, a lot of what's happening right now, both for drilling rigs and for pressure pumping is a result of where commodities were a couple of months ago. Well, commodities are in a different space right now, so if you look forward a couple of months, if it stays at this level, then our schedule for the frac looks a lot better.
Your next question is from Derek Podhaizer of Barclays. Please go ahead. Your line is open.
I know you talked about having some confidence that the rig count is going to bottom here. You talked, I think you said, 10 rigs and 6 came off and 2 more, and we'll get 2 more after that. Are you just having conversations around starting rigs up in the fourth quarter or end of the third quarter? Are you signing rigs yet? Just a little more color around your confidence that we'll see rigs start being added as we get towards the end of the year.
I think it's really just, for us, right now, it's based on where the commodities are trading. Our customers are going to start their budget cycles here pretty soon. And we feel like when commodities are at this level, and this has happened historically that soon after their budget cycle or even sometimes in the middle, we start to get phone calls to accelerate things. If commodity stays where they are at these levels, I don't think you'll see the traditional Q4 that gets a little bit soft at the end, I think you'll see a fairly stable Q4 going into the end of the year.
Got it. That's helpful, switching over to pressure pumping, obviously, white space is putting downward pressure on your profitability. Can you just talk about when you merge with NexTier and you fold into the NexTier integration strategy. How should we think about those synergies that you could unlock? What are you missing today that NexTier provides and where do you expect profitability to go as you continue to upgrade these assets to Next Gen and you fold into the wells integration strategy that next year brings to the table?
Yes. If you look at our fleet of 12 spreads, their performance of the customers they're working for is very strong, they're very competitive. And we're going to have 10 dual fuel spreads. So it's very marketable 12 spreads that we have.
As we roll it into NexTier, what we're really going to gain is the integration of all the other ancillary services that we can layer on there. whether it's wire line, logistics, sand handling, things like that, the power fuel systems that they have for natural gas blending at the well site, so we'll be able to layer that over time on our 12 spreads, and that's where we get a lot of upside on the 12 spreads that we're running today.
Your next question is from Keith MacKey of RBC Capital Markets. Please go ahead. Your line is open.
I just wanted to start out on the pricing in the drilling market and what you're seeing in that low to mid-30s day rate. Can you just talk maybe about some of the regional dynamics? We heard earlier in the year, of course, that gas basins, particularly the Haynesville were softening more than oil basins, but with some of those rigs moving over to oil basins, maybe the pricing there has taken a hit. So can you just kind of run us through what you're seeing in the various basis for pricing and how you think that will play out as we go through this modest recovery in rig counts?
Yes. If you look through the year, it really kind of started with the Haynesville getting soft and then other basins that feed into Henry Hub, like South Texas, Mid-Con, those various basins have produced gas, and so that freed up rigs. Some of those rigs left gas basins and pushed it into oil basins. We didn't actually move any rigs from gas into oil. We're leaving our rigs where they are. We think there's upside there.
The Northeast gas held pretty steady through most of the year up until recently, but I think they're seeing a little bit more stress in the Northeast. So, I think there's a little bit of a slowdown up there, not to the extent that we're seeing in the Haynesville and other areas tied into Henry Hub, but a little bit of stress up in the Northeast. And I think that's going to affect things for a little bit. But again, just looking at the forward strip, if that holds in, all the stress gets relieved for our E&P customers and their economics start to improve.
Mike, do you want to add anything on that?
Yes. I think your concept is probably right. If you look at a hotter basin like out Permian, if there's some new activity, it's going to be competitive. We really haven't participated in that. We've lost some bids out there, but to price. But I think for us, it's been pretty stable across the markets because we're not going to chase that work if it's not in the range that we're looking for.
When you're a large drilling contractor and you work a large number of rigs, when you lose a few like we've had, and we're only down about 12% since the beginning of the year on our projections. That's not a huge move for us, if you're a smaller drilling contractor, and you lose the same number of rigs. That's a big hit and you've got to work hard to keep rigs working at that point. We get that there's competitive bids out there for rigs, but we don't chase that.
Got it. Makes sense. And just a follow-up on the pressure pumping side. Can you talk a little bit about the timing you expect for the Tier 4 dual fuel conversion to be in the field? Like should we be thinking about Q4 as a full quarter of 12 spreads? Or will that be partially through the quarter would you say?
I would think about it as Q4. It does take a little bit of time. And sometimes when we mobilize one of those, we may still be adding some more of the Tier 4 dual fuel trailers while we started the work, but I still think about it as Q4.
Your next question is from Saurabh Pant of Bank of America. Please go ahead. Your line is open.
I guess I'll start with maybe a follow-up on your expectation for recon because it seems like there is some optimism that the industry might be adding rigs towards the latter part of this year. Just to get some clarity or clarification on that. It sounds like that optimism is more on the oil side and the gas side of activity rebound is more of a 2024 thing, right? I just wanted to clarify on that, if that's correct. And then what is driving that? Is it more public versus private? Or how should we think about who's driving that uptick in the latter part of this year?
I'm actually upbeat on both oil and gas when you look at Q4 and you look at where the forward strip is. We do actually have some gas customers that will probably drill into where that forward strip is. We've got gas customers today that are already layering in hedges for next year at over $4. So while oil is certainly in a good spot right now, and I'm upbeat on that, I'm upbeat on both.
Yes, I think we've had conversations in some of the gas basins for Q4 start-ups there for next year's programs, but they'll get started a little bit early, and so I think we're seeing it both. And on the question on the public and private I would just say, the way to think about that is the privates typically react a little quicker in either direction. So, I wouldn't be surprised to give that maybe Q4 they may outpace the public, but there's going to be a smaller switch. So it's -- I'm not sure we can really call it, but I think there's generally privates that react a little quicker.
Right, Okay. No, perfect. That's very helpful. And then maybe a quick follow-up on the preparing side, you commented on activity 11 spreads in the third quarter going back to 12 spreads in the fourth quarter. How should we think about that from an entering 2024 perspective? Because earlier in the year, you had contemplated doing a 13th track thread out in the market, I know the merger with next year is outstanding, so that might change dynamics, right? But how should we think about 2024, potentially could you be adding that 13th tax spread if there's demand?
Listen, I appreciate that question, but it's tough to talk about 2024 yet. We'll address that on the next call when we're looking at a much larger fleet of over 40 frac spreads.
Okay. No, I guess I've got a little carried away with all that optimism. Thank you, I'll turn it back.
Your next question is from Jim Rollyson of Raymond James. Please go ahead. Your line is open.
On the CapEx front, Andy, the remaining $485 million, is that relatively spread out over the back half? Or is it kind of distributed differently than evenly?
No, it's pretty spread out over the back half. Again, a lot of that is -- as we've come back and some activities falling off, we've seen some maintenance cap come back. Some of the growth items that we had in there were sort of committed now we'll push a few out a little bit, but it should be pretty spread over the back half of the year.
And I know this will be a tough question, but as you think about where you're looking at activity based on the kind of optimistic view heading into next year. If you were talking apples and apples, do you think your CapEx next year would be flattish from this year or down just because you're not going to be reactivating a number of rigs like you did in 2023? I realize all that.
Well, I mean, look, it depends -- maintenance CapEx will be what it is, right? I mean it's obviously linear with activity. On the growth side, again, as we put rigs back to work, it depends on your point of view as to where you think the rig count is going ultimately in 2024 as to whether or not we would need any kind of significant upgrade.
Remember that a lot of the upgrades that we were doing this year were paid for by our customers in advance last year. And now we don't get to show that amount net. We show that amount grows in terms of our CapEx. So again, depending upon your point of view going forward, you can probably see it being something less on the growth side than what you would typically see or what you have seen in the typical last few years.
Yes. And especially considering some of these rigs have worked recently, there's not as much CapEx necessary to put them back to work. So I think considering -- if you're considering an inverse curve on activity moving up in '24 versus what we had softening in '23, then I think CapEx would be level to maybe even a little bit lower. So I think we can be really efficient next year apples to Apples.
Makes sense. And then last thing, just kind of following up on pressure pumping. Obviously, you talked about in general, and carrying some extra costs as you drop a fleet, which has obviously impacted profitability. Has there been any material change? Like what have you seen from a pricing and kind of commercial terms dynamic in this kind of air pocket of activity here recently?
Well, we've seen the dedicated pricing hold up relatively well, maybe some small adjustments for some customers, but not a lot, but it's really the spot market that's come down maybe 30% or so. But that's it's the spot and it's temporary. And if activity is increasing like we think later in the year and into next year that will reverse as well.
Your next question is from John Daniel of Daniel Energy Partners. Please go ahead. Your line is open.
Just one question for you today, and when you think of all of the E&P M&A that we've seen where buyers rationalize activity, it would seem getting back to the activity highs, if you will, of late '22 might be tough to do in '24? I'm just curious if you're seeing anything that would sort of dispute that theory.
We are seeing some mergers on the E&P side, but at the same time, we're seeing some E&Ps sell off some of their properties too and some smaller companies come into play, where they've got to prove up that acreage. And so, I do think the rig count has a chance to get back to the highs of this year. As you know, the rig count never moves up at the same rate it comes down, but that doesn't mean it can get back to where it was. I think there's enough people with interest to drill out there even with the mergers to get back to where we were.
Okay. Got it. And I'm going to try to rephrase this straight away. Let's say E&P A buys company B and they did an drop a bunch of rigs, are you seeing that E&P A person coming back in wanting to add back any of those rigs that they stated they were going to drop? You follow that example?
Yes, I don't know if I have a good example of that for us.
Fair enough. Okay. That's all. Thanks for including me.
Your next question is from Dan Kutz of Morgan Stanley. Please go ahead. Your line is open.
Maybe I'll just follow up on John's first question there. Thinking about 2024 activity and whether or not it could get to the highs of this year, would you kind of frame gas activity as having a better chance of getting back to this year's levels with all of the LNG liquefaction capacity coming online? Or I guess, how would you frame whether gas or oil or boats have a better chance of kind of getting back to this year's highs?
Well, it's gas that had the bigger downside earlier in the year, and I think it's gas, it has the upside. I think -- I'm not discounting oil, oil can still move up from where it is in terms of activity, but I think there's more upside on the gas. If you look at some of the E&P transactions, let's say, South Texas, where you've had properties change hands, some of these E&Ps that have acquired some of these properties are now making plans to drill them and we're part of those plans.
So, I still see some upside in gas I don't think of it just as Haynesville. I think of it as the broader basins that are connected to Henry Hub from South Texas all the way to Mid-Con. And so, I still think there's more upside on the gas side.
Got it. Understood. And then just on the 50% total shareholder return target, apologies if you guys have already made this clear, but I understand that once the deals closed that you guys and next year have endorsed that target moving forward. But are we to understand that Patterson is still maintaining that target kind of in the second half of this year as the two deals are slotted to close? Or could M&A interrupt that 50% target in the second half of this year?
Well, what we've said all along is our intent is to return 50% of the free cash flow to the shareholders, and we don't -- we think of it more on an annualized basis. And whether you take that as the starting point from when we first said it in October last year, you take it from the start of this year, we're ahead of the schedule, depending on it doesn't matter where you take your starting point.
So we've already given back more than 50% of the cash to the shareholders on an annualized basis. And so we're ahead of that. But I wouldn't worry about the M&A disrupting that. And certainly going forward, with the combination of next year, we still intend to return 50% of the free cash flow to shareholders.
There are no further questions at this time. I will now turn the call over to Andy Hendricks for closing remarks.
Great. I want to thank everybody who have dialed into the Patterson-UTI call this morning. We're excited about great things that are happening in the future, and our call is going to look very different next time, but thanks again for dialing in.
This concludes today's conference call. Thank you for your participation. You may now disconnect.