Good day, everyone, and welcome to Helmerich & Payne's fiscal second quarter earnings call. [Operator Instructions] Please note this call is being recorded. [Operator Instructions] It is now my pleasure to turn the conference over to Mr. Dave Wilson, Vice President of Investor Relations.

Thank you, Abby, and welcome, everyone, to Helmerich & Payne's conference call and webcast for the second quarter of fiscal year 2024. With us today are John Lindsay, President and CEO; and Mark Smith, Senior Vice President and CFO. Both John and Mark will be sharing some comments with us, after which we'll open the call for questions. Before we begin our prepared remarks, I'll remind everyone that this call will include forward-looking statements as defined under the securities laws. Such statements are based on current information and management's expectations as of this date and are not guarantees of future performance. Forward-looking statements involve certain risks, uncertainties and assumptions that are difficult to predict. As such, our actual outcomes and results could differ materially. You can learn more about these risks in our annual report on Form 10-K, our quarterly reports on Form 10-Q, and our other SEC filings. You should not place undue reliance on forward-looking statements and we undertake no obligation to publicly update these forward-looking statements. We also make reference to certain non-GAAP financial measures such as segment operating income, direct margin, and other operating statistics. You'll find the GAAP reconciliation comments and calculations in yesterday's press release. With that said, I'll now turn the call over to John Lindsay.

Thank you, Dave. Good morning, everyone. In light of the choppy market conditions in the U.S., Helmerich & Payne is pleased with our second fiscal quarter results. Even with these shifting market conditions, our margins remain strong, reflecting our continued focus on maintaining commercial economics, commensurate to the value we're delivering to customers. We're also encouraged to see evidence that there's an ongoing and necessary shift in the industry's fiscal behavior, which is moving it toward a more sustainable and investable future. In the U.S. market, contractual churn is still prevalent, and while we achieved our average planned rig count for the second quarter, our exit rig count for the quarter was just below what was projected. Mark will give more rig count details during his remarks. But let me summarize by saying that part of this churn continues to be a product of the volatility created by a weaker natural gas market and is reminiscent of the volatility experienced this time last year. However, we believe the impact on our overall activity will be less this year going forward. E&P consolidations and a variety of other factors have also contributed to churn, and while we expect many of these underlying factors will persist, we are also projecting a relatively stable outlook for our rig count through the third fiscal quarter. We expect our total projected North America solutions direct margin for the third fiscal quarter to be down slightly on a sequential basis due to a lower average rig count. But it's important to note that we also expect resiliency in our per-day direct margins. Our customers benefit from reliability, faster well cycles and better well quality, all of which lowers their total well cost. Our ability to deliver consistently on these measures is what ultimately drives direct margins…

Thanks, John. Today, I will review our fiscal second quarter 2024 operating results, provide guidance for the third quarter, update remaining full fiscal year 2024 guidance as appropriate, and comment on our financial position. Let me start with highlights for the recently completed second fiscal quarter ended March 31, 2024. The company generated quarterly revenues of $688 million versus $677 million from the previous quarter. Revenues were up sequentially, primarily due to an increase in average active rig activity in North America. Total direct operating costs were $403 million for the second quarter versus $404 million for the previous quarter. General and administrative expenses were approximately $62 million for the second quarter, which was higher than our expectations due to a few discrete items, including information technology costs, mark-to-market adjustments for director deferred compensation, and the incurrence of certain professional services and consulting fees. During the second quarter we recognized gains of $3.7 million primarily related to the change in the fair market value of our equity investments, which is part of the gain on investment securities reported in our consolidated statement of operations. Our Q2 effective tax rate was approximately 27.5%, which was within our previously guided range for the quarter. To summarize this quarter's results, H&P earned a profit of $0.84 per diluted share versus $0.94 in the previous quarter. As highlighted in our press release, second quarter select items had a neutral impact on diluted earnings per share. For comparison, diluted earnings per share of $0.84 in the second fiscal quarter versus $0.97 during the first fiscal quarter after adjusting Q1 for select items. Capital expenditures for the second quarter of fiscal 2024 were $118 million and I will have some further comments when we come to our fiscal 2024 capital expenditure guidance. Our Q2 cash flow…

[Operator Instructions] Our first question comes from the line of Doug Becker from Capital One.

John, if you allow me to dream a little bit, it does seem like the rig counts as stabilizing, but was just hoping to get an update on how you see supply and demand for the super-spec market in particular? And when conceptually we could see pricing power again if -- the outlook for next year, higher oil prices a little bit better, natural gas price outlook? Just want to get a sense for where the lay of the land is and what a little bit of bull case is?

Sure, Doug. I think if you just look at the activity set over the last several years, the super-spec segment of the market continues to grow on a percentage basis. Obviously, we've had a pull-back in activity, both H&P and the general industry in general, primarily as a result of natural gas prices like we've talked about. But I think it's -- I think the outlook is very positive. I think the ability to continue to drive efficiencies and reliability, do it in a safe fashion and leverage technologies are really those key things that are going to be needed. That's what customers are looking for. So, I feel good about overall the super-spec space in the U.S. In terms of trying to pick the timing, as you know, that's very challenging to do, but obviously oil prices are strong. But the gas basins we've had quite a bit of pullback in activity. But again, I think that's -- we'll see some improvements here in the future.

Fair enough. And Mark, I know you expressed comfort with the cash flow outlook. Just wanted to try and reconcile a lot of the moving parts. My assumption would be that free cash flow would be below the, say, $235 million, that previous guidance implied just given most notably the higher CapEx. Is that fair, or am I missing a factor?

It's in the ballpark.

Our next question comes from the line of Derek Podhaizer from Barclays.

Maybe just to continue the line of questioning. You talked about in your prepared remarks, you're seeing signs of leveling off in the rig count. Can you maybe just expand on that, what you're seeing? Is it customer conversations, is it DUC counts? Just any way you can help us with the signs that you're seeing as far as leveling off on the rig count?

Well, Derek, it's really a function of conversations that we have ongoing with customers. There's obviously this continued churn that we've described, but there are examples where customers have rig opportunities where they're picking up. There's also some high grading that is ongoing really continually as we move forward. If you just look at our count in general, the H&P count, we've been in a 5 -rig range since what -- since June of last year. And again, we all know what the challenges have been with natural gas. So really, our outlook and our expectation is really derived from conversations that we've had with customers and what their expectations are. You've heard me say before, it's very hard to forecast out much past a quarter. It's -- there's a lot of things that can happen in a short period of time. But based on what we know right now, the feedback we're getting, that's the estimate that we've put together.

I wanted to dig into the performance-based contract. So, one of your customers announced their company record 5-wheel pad, all 4-mile laterals last night. Is this a good read through of how you capture value in generating efficiencies for your customers? Maybe describe the mechanics of an example like that?

Well, that's definitely a great example. At the end of the day what we're doing is we're having conversations with customers, we've -- you've heard us talk about before. This is a partnership, and we work very closely in trying to understand what their deliverables are, what makes for -- them looking -- seeing what would be a positive outcome, and whatever that metric is, that's the focus that we have. At the end of the day we've got to deliver wells more efficiently. We've got to save days, we've got to improve well bore quality, consistency. The technology solutions that we have really help deliver that. So if you can put together a performance-based contract -- construct that really rewards the service provider, in this case H&P, and aligns it with the outcomes that the customer is wanting, then that's a true win-win outcome, and that's the best that you can hope for. And as you've heard us say, at the end of the day, we're making big investments. This is a capital-intensive business and we're making big investments. And those investments are designed to enhance the quality and the performance. At the same time we have to get returns above our cost of capital. Otherwise it's very challenging for us to be investable today and into the future.

Our next question comes from the line of Saurabh Pant from Bank of America.

Mark, maybe I'll start with one clarification for you. You did give a good color on CapEx, and you have better line of sight from a supply-chain perspective. But if I recall your messaging from last quarter, I think there was a part $30 million, $35 million, you said, in additional CapEx related to the Saudi rigs that was expected next year. So, is there an element of that being pulled forward to your FY '24 CapEx going from $450 million to $500 million to now $500 million, or is that still expected to be incurred in FY '25?

Thanks for the question, Saurabh. No, that's still anticipated to be incurred in 2025. I think I had said, or if I didn't, I'll say it now, we're approximately $27 million CapEx, all in for each of these Saudi Arabia rigs. And that's no different than the number we were giving in building our models around this time last quarter. What I will say though is we always have a range, and it's really hard quarter-to-quarter to know exactly how the timing is going to fall when you're working with a very wide supply-chain and 150 active rigs in the U.S. and trying to catch up, as we've said on previous calls for maintenance capex, for componentry, even going back to the cannibalization we experienced in 2021 coming out of the pandemic. So as we're 2 quarters into a 4-quarter year, we have a little more certainty around that maintenance CapEx timing. And that is really one of the largest components of driving up towards the top end of the range.

Okay. And then, John, maybe one for you. Just the narrative over the past 3 months, internationally, particularly in the Saudi market seems to be that there's a lot more emphasis on gas. And clearly, that's where you are going with your rigs. And just based on discussing with market participants there, it seems like there might be more tenders coming for more rigs in the Saudi market for unconventional gas. Is there something you can share with us, John, in terms of what you are seeing out there in terms of opportunity for growth, and further rig additions there for Helmerich & Payne?

Saurabh, that's a great question, and really I can't add anything more than what you probably already read out there in the market. We've read the same thing and heard similar rumors about the potential for additional tenders for unconventional gas going forward. We're hopeful that, that is, in fact, the case. But like you, we'll be standing by and waiting to see if that is in fact the case, because we don't have any direct information on that.

Our next question comes from the line of Keith MacKey from RBC Capital Markets.

Just like to start with your comment there about increasing service intensity. Can you just expand a little bit on what that means for Helmerich & Payne in terms of specific revenue or cost opportunities? And secondarily, is it leading customers to want to use the performance-based model more, or want to use the day-rate model more, or are there just other factors in there that are driving whatever decision might happen?

I think, try to summarize when we think about service intensity. We talked about, I think, on our last call that laterals have more than doubled over the last 5 to 7 years, and we're drilling those wells in far fewer days. And of course, the end result is more exposure to the resource, better outcomes, better returns for our customers. At the same time, our equipment continues to work harder. You just heard Mark talking about maintenance CapEx. And so maintenance CapEx continues to go up on a per rig basis. And that's largely -- and a large part of that is -- has to do with that service intensity. So what we're doing is, yes, the performance-based contracts are important because it helps you align with the outcomes that your customer is wanting to achieve and you're creating a value proposition that you're getting paid for in the process. So without going into great detail, that's really the concept behind it. And it's not just drilling rigs. I mean its pressure pumping. It's across the board. All of the equipment in OFS is really working harder in these more challenging well designs, longer laterals, and much, much faster cycle times.

Okay. Can we just talk a little bit more about the Saudi rigs? It looks like there's a batching process of them being sent over. Once the OpEx portion or the start-up costs are spent, that Mark outlined, do you expect there to be more costs -- similar costs in fiscal 2025, or should that be it? And then, when roughly do you think that these rigs will get up to their appropriate run rate for revenue and margin profile?

Thanks for the question, Keith, but most of this recommissioning expense will be largely incurred in the fiscal '24 that we're in. As I mentioned in the prepared remarks, $10 million to $12 million is expected in fiscal Q3 and then another $5 million for that recommissioning in fiscal Q4. And then they start being readied to put on [ those ] and mobilize to the Middle East. And when that happens, there will be a cash expenditure of $2 million for mobilization per rig, which will be deferred and recognized over the contract term, together with the corresponding mobilization revenue once the operation is commenced. So that stuff is largely at 2025 and then through the life of the contract as the recognition. We think that these rigs will mostly be exported through this calendar year and commence turning to the right and operations is budding and the beginning of calendar '25.

Our next question comes from the line of Scott Gruber from Citigroup.

I want to stay on the Saudi rig topic. I want to ask about the cost structure in country. How do you think about your ability to lessen that over time? Did you gain experience operating in the country?

I'll take a stab at that, John, and then please add in. There are several different things, and obviously, most of our daily costs are related to the labor. We're certainly starting with what will be -- we have some costs that we're incurring in country now as we've set up an office and are beginning to hire people. And we'll be starting with a large complement from our North America Solutions segment so that we ensure safe and efficient and effective startups. But through time we will begin to have local crews and transfer knowledge. I think a prime example of -- demonstrates how we can do that is Argentina. Today, and for some time, there's not been a single U.S. expat in that country while we're operating 8 or 9 super-spec rigs and have a similar market share position in the Vaca Muerta to what we have in the U.S., albeit at a smaller scale. There's also supply-chain benefits through time that we'll get. We obviously are doing all this work in -- at our facility in Galena Park, to do the equipment recertification, recommissioning, et cetera. But once we're in country, we'll have a couple of things that will be helpful. One, because these rigs are "like new", in their 5-year contract term we expect minimal maintenance CapEx through the initial 5 years. Two, we'll be developing through that time our supply chain apparatus in the country as we look to have in country -- in kingdom value spend. And that will also make us more efficient, we believe, locally with not only maintenance CapEx, but materials and supplies, inventory consumption as well. So we're working on a lot of these efforts and we're excited about the opportunity to put all these ideas to work.

Got it. Appreciate the color. And then turning back to the U.S., the customer consolidation in E&Ps, obviously should be beneficial for HP. You guys have highlighted that. I'm just wondering, now that we're starting to see some deals close, at least from the recent wave, are you having conversations that suggest some consolidation-driven share pickup, is the distinct possibility for HP in the near future?

Scott, I don't -- I really don't want to get into those details. I mean, again, I think when you look at consolidation over time -- I think, when I look back at H&P, and we've been -- we've come out on the good end on many of the consolidations over the years. And our expectation is that we'll continue. I mean, at the end of the day, it comes back to no surprise what we've said before, and that is the ability to deliver safe, efficient and reliable performance. And I think as long as we can continue to do that and have strong partnerships with our customers, that we will come out in a great place over time.

Our next question comes from the line of Marc Bianchi from Cowen.

I wanted to go back to the Saudi margin opportunity there, because I think you previously outlined it as more than $25 million for the 7 rigs, which would compute to something just below $10,000 a day. It sounds like there's a fair bit of overhead. But when I look back at the international business for H&P over time, the margins don't seem to really get up above $10,000 a day. And I know it's different geographies and such, but you made the comment about historically Argentina operating. So I'm just curious, where do you see the opportunity in margin for Saudi? Should this ultimately look more like what we see in North America, or are there just factors that we've seen with international historically that would keep this closer to $10,000 a day?

Marc, thanks for the question. And let me just say on one hand, no, the $10,000 a day that you're coming up with is not a marker for 2025 or thereafter. Having said that, there's certain details we're not going to get into for competitive reasons here. As was previously stated on this call, we do expect future tenders in a competitive bit tender environment in the -- going forward. We've done our internal modeling for returns that get us to our IRR hurdles on the $27 million investment per rig. That's one thing to note. Another thing to note is that, as your reference to my comment on Argentina this morning, we've only recently gotten to that no U.S. expat status with our focus on cost management, the last couple of years. And I will say historically, in our business, not just H&P, but the onshore drilling industry, for U.S. drillers moving internationally, we did not do a great job of scale. We would go into countries with one or 2 rigs and we would set up an entire SG&A apparatus to support it. And we have said for a couple of years on these calls, that is exactly the opposite of what we will do going forward. We started with one rig last August. We've just added 7 to get 8. We will begin to see benefits of scale as we get local content both in terms of people and supply chain, and we will continue to add to that scale. We will also be leveraging more of a supply chain back-office support for the corporation, and are excited about things we can do for this that are very different than that historical experience you just outlined.

And this is John. And I think just to add to Mark's comments. Specifically in Saudi, obviously, it's unconventional. We have a lot of experience with unconventional. Again, our -- there was a question earlier about additional tenders. My assumption is over the next several years, there'll be more tenders. And our expectation is that we would be successful and we would be successful because we're going to be providing and adding value for Aramco. So that's my hope. The other factor that we haven't really talked much about is the technology aspect of our offering, and there's some opportunity there. Again, as you think back, as you think about what we're doing in the U.S. and the unconventional play, and how we've been doing this work in the U.S. all these years, and yet we continue to have year-over-year improvements that -- in a lot of cases are driven by technology. So that's the other upside component to this with H&P.

Mark, I wanted to ask one more on kind of the maintenance CapEx. I think previously, we go back and it was like $1 million a rig per year. That was increased to like a $1 million, $1.3 million. And then the latest comment was it was maybe between $1.3 million and $1.5 million, if I remember correctly. And now it sounds like maybe there's some upward bias to that. Can you talk about how much of that is sort of just this hangover from the cannibalization period versus what could be sustainably a higher run rate over time?

Sure, Marc. If you think about fiscal '23, so go back a year and look at our maintenance -- look at our CapEx -- maintenance CapEx, specific guidance for fiscal '23 at the beginning of the year. And when we ended '23, September 30, we did not spend that amount. So we had revisions downward and we had a lot of supply chain constraints. What we've seen this year is the supply chain finally responding with more throughput so that we can do this catchup we've been talking about for quite some time. So what you see is transitory amounts here, as we've been able to nail down the supply chain. The componentry in question, it's all sorts of stuff. It's 7-year top drive, its 5-year BOP, its engine work, its mud pump work, et cetera, et cetera, et cetera. So it's across the full stack of componentry on the rig. And I would say, as I look at the list of components and work with our U.S. operations and maintenance teams, we're starting to see where we're turning the corner on some of these components. So the volume that we've had to get through should come start to tick down, I would hope, in 2025, and then -- but I will say we do have some inflation that will be sticky. So will we ever get to under $1 million? I don't see that necessarily, but I think the [ $1.4 million ] that we started this year with and [ one ] somewhere between those 2 and another year or 2 looks to be a [ good zip code ].

Our next question comes from the line of Waqar Syed from ATB Capital Markets.

A couple of questions here. First of all, John, with oil prices in the 80s and the Permian DUC inventory relatively low, I know you mentioned you're seeing kind of a flattish market, but do you see any hope of any pickup in activity in the Permian for H2 and perhaps for next year?

Well, we're always hopeful and I did mention that the longer term outlook, the fundamentals are strong. Obviously, oil prices are strong. The activity set, that we're experiencing this correction in activity, as you know, is a function of natural gas, not oil. And so, I do think the Permian has a lot of potential. Obviously, we're the largest driller, have the most rigs running in the Permian. And quite frankly, I think the rig count we have today is essentially the same as it was when we had close to 170, 180 rigs running, right. So we've done very, very well in terms of maintaining our market share, actually growing it a little bit in that basin. So I think the outlook is good. The big question, as we all say, is well, when is that opportunity to add back units. And again, our hope is we'll start to see some improvement in the back half of this year. But again, at this stage, it's just a hope, because we don't really have any additional information than you or anybody else does.

No, we do hear that with these -- some of these big E&P consolidations, once they're consummated, you may see, or you're seeing some geoscientists come out from these consolidated companies or become redundant and some private capital is chasing them and new companies are being formed. And that you may see private activity maybe pick up in the second half or maybe in 2025. Are you seeing any early signs of that? Are you having any conversations in that respect?

Well, as you probably know, most of -- I think 80% of our active fleet today is with large public companies. However, we do have nice partnerships with the private. And there are some examples where here recently -- just recently in the past quarter we put a rig to work for various small private companies. So I definitely think that, that's an opportunity. Clearly, the consolidation that we see usually in the first period of time, there's some slowdown in activity. But at the end of the day, they're going to want to keep their production levels up. And in many cases that means keeping the same amount or even adding some rigs. So -- and then the additional private companies, we could sure see that happening. It's happened in the past and maybe it will happen in the future, but hard to say much more about that, Waqar.

Okay. And then just one final question, that as the service intensity continues to increase now going to these 4-mile type laterals, some companies, are you seeing the super-spec rig specifications kind of change again or step out again? Or the rig of choice -- super-spec rig of choice for the last year or 2 years ago is still pretty relevant?

Very relevant. We have been able to handle these 3 and 4-mile laterals with the [ kit ] that we have. There are times where you may need to upside the setback capacity or something like that. But in general, the FlexRig is very well suited for the work that is required and ongoing. So, we feel really good about where we are. Like I said earlier, we think there'll be more demand for super-spec, not less. It's going to be harder and harder for the lower tier rigs to be competitive because of the length of the lateral and the performance that's required. And then just finally, on the technology side, it's very, very difficult for a human to keep up with what a computer or the technology is going to do. So this is 24/7 work and the ability to have apps and algorithms that are doing the work, making the decisions, as opposed to it being done by a human 24/7. It's night and day difference. So the technology opportunity set is huge. And whether that's a 2-mile lateral or a 4-mile lateral, we're going to see more and more of that adoption, I believe, as we go forward.

Our next question comes from the line of Kurt Hallead from Benchmark.

John, I'm curious, right, what your take might be on your conversations with your customer base looking out beyond 2024? A lot of hope and opportunity with respect to exporting gas for these LNG facilities that are scheduled to come online. And then on top of that, a lot of discussion of late around the data centers and AI and the need to power that dynamic and that needing more rig capacity and that needing more natural gas. Long winded way of asking a question is, are any of these topics on the front of mind of your customer base? And how do you think about how that's going to translate into incremental drilling activity, first for LNG going into next year, and then potentially looking at the dynamics related to the data center?

Well, Kurt, it's a great question, and it's a question on everybody's mind, and no doubt there's a lot of opinions out there. And our opinion, our hope is that it's going to be sooner as opposed to later. I think at some point in time it's definitely going to happen on the gas side. It's just that natural gas is just a great energy source for lots and lots of reasons. And there's a huge opportunity ahead. Obviously, the unconventional gas, that opportunities that we see in the Middle East. So there's a market out there, and I think there's a huge opportunity ahead for us. It's just -- as I said earlier, Kurt, it's hard to say when that's going to be. I think we're going to play -- H&P will play a very large role in that when that recovery takes off, just like we were playing previously before the correction in the natural gas activity.

And just follow-up on. I noticed here that you had very minimal share repurchase activity during the course of the March quarter relative to the December quarter. Just kind of curious as to what those dynamics were driven by? And was it related to the Saudi contract, or anything else that kind of you guys had to put the pause on?

Kurt, thanks for the question. In our original capital allocation guidance in October for our supplemental plan, we outlined the fiscal '24 supplemental dividend of $68 million plus, quote an allocated cash of $68 million. To-date in this fiscal year, we repurchased 52 million of shares primarily in fiscal Q1. That said, we have further projected free cash flow as well as cash on hand in excess of our previously stated target of $200 million. We slowed calendar Q1 repurchases as the rig count looked to soften a bit and -- as previously discussed this morning, and due to macro uncertainties in the market overall, we will continue to be opportunistic while maintaining our longstanding financial stewardship.

Our last question comes from the line of Jeffrey LeBlanc from TPH.

I just had a quick one. Given the success that you've had in maintaining margins and day rates, do you believe that operators will still be amenable to day rate increases to offset reactivation costs moving forward, particularly when you see natural gas prices recover?

Well, Jeff, I can really only speak to the H&P -- from the H&P perspective. The rigs that we have idled over the last year are rigs, at least in my view, would be ready to go to work, would not require much startup expense. We're not cannibalizing our fleet. So we have available capacity. I can't tell you right now for sure what that would be. But I wouldn't expect that there would be a lot of startup CapEx that would be required. Now, again, I'm making an assumption that, that's happening in 1 year timeframe from being idle to going back to work, 1 year, 1.5 years.

That appears to be all the time we have for questions. I will now turn the program back over to Mr. John Lindsay for any additional or closing remarks.

Thank you, Abby, and thanks to everyone for joining us today. We're very excited about the future and the opportunities ahead. And we'll now sign off. Thank you.

This does conclude today's program. Thank you for your participation. You may disconnect at any time.