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

Thank you, 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 and market share. Oil prices remain attractive, and we see the customer outlook becoming more positive regarding medium and long-term energy fundamentals. Based on that, we believe there will be growing demand for the top-performing super-spec rigs due to customers deploying well designs that require technologies to drive stronger economics from their acreage positions. Intersecting with this is the major industry theme of service intensity, where daily rig costs are higher because laterals are longer and circulating pressures are higher to drill these wells. All these elements coalesce to create the opportunity for technology and performance-based contracts that demonstrate the performance differentiation H&P brings to the table. Our operations and sales teams are working more closely than ever with the customer to deliver more collaborative solutions. Regarding our International Solutions segment, we are busy preparing for the unconventional project in Saudi Arabia that we announced last quarter and have finalized the contractual terms for the 7-rig tender award. Our first rig awarded by Saudi Aramco in August of 2023 is expected to arrive and commence operations later this summer. For the recent 7-rig tender awards in January, preparations are ongoing from both a rig and operational perspective, with expectations that a majority of these rigs will arrive in Saudi Arabia during the fourth calendar quarter of 2024 and commence operations shortly thereafter. During these preparations we'll continue to spend our 2024 budgeted CapEx towards this project and incur start-up operational expenses, which will disproportionately impact near-term International segment margins. We look forward to working with Saudi Aramco and believe this is the beginning of a long-term presence in the region with additional growth opportunities. International operations in South America and Australia are expected to remain relatively stable over the next quarter as well as our offshore Gulf of Mexico operations. In addition to our international growth strategy, our capital allocation strategy this fiscal year is structured with a base and supplemental dividend as well as opportunistic share repurchases, and Mark will provide more details in his remarks. I want to conclude my prepared remarks by stating again, we have remained firm on our contractual economics by working with and collaborating closely with customers on alternative contract models. Our primary commercial model today is using performance contracts combined with our technology solutions. Having the operational confidence in our ability to consistently execute with our technology solutions results in win-win economics for both the customer and H&P and provides our customers with safety, consistency, and reduced execution risk. All of these successes are possible because of the people at H&P. It is you who make our FlexRigs and our technology solutions the best in the industry. Each of you plays a key role in our success and will continue to be drivers of that success in the future. And now, I'll turn the call over to Mark Smith to provide more details and a review of our financials.

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 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 from operations was $144 million, which was as expected, showing a sequential decline in part due to most of our year-to-date cash tax payments falling into the second fiscal quarter. I will address the company's cash position later in my remarks. Turning to our 3 segments. Beginning with the North America Solutions segment, we averaged 155 contracted rigs during the second quarter, up from 149 in the first fiscal quarter. The exit rig count was 152, which declined late in the quarter and was below our guided range of between 154 and 159, due to lower natural gas prices and miscellaneous individual customer factors. Revenues increased sequentially by $19 million, primarily due to the increase in average activity quarter-to-quarter as well as some remaining legacy priced rigs rolling to current market rates. Segment direct margin was $271 million, which was towards the high end of our guidance and sequentially higher than the previous quarter, which came in at $256 million. Total segment expenses were down slightly to $19,000 per day in the second quarter, compared to $19,600 per day in the previous quarter. Looking ahead to the third quarter of fiscal 2024, for North America Solutions segment, as of today's call, we have 150 rigs contracted, and while activity through most of the second quarter was strong, the previously mentioned factors began to wear on the market and today the rig count has reverted back to a similar level to January 1st. That said, we are seeing signs that the rig count seems to be nearing a leveling off point, and we expect to end our third fiscal quarter with between 145 and 151 working rigs. It is worth noting that among the various factors impacting the rig count, pricing is not one of them, and to that end, as mentioned in the press release, we remain focused and steadfast on our commercial economics. Furthermore, despite a slight decrease in our rig count heading into our third fiscal quarter, we have been able to maintain and even accrete market share since our fiscal 2023 year end, U.S. land share of 25.5% to a 27.5% share today overall, while maintaining a 33% to 34% super-spec market share. As we have commented before, market share is not our main goal, but rather providing value to customers and being adequately compensated for our performance and value created. We believe our financial margins and market performance are representative of our efforts. Revenue backlog from our North America Solutions fleet stands at roughly $1 billion for rigs under term contract. As of today, about 57% of the U.S. active fleet is on a term contract. Average pricing and revenue per day should remain relatively flat. In the North America Solutions segment, we expect direct margins in fiscal Q3 to range between $255 million to $275 million, and we expect costs in Q3 to remain relatively flat. Next, to our International Solutions segment. International Solutions activity ended the second fiscal quarter with 11 rigs on contract. International Solutions results were above our guidance range as the inflationary environment in Argentina was less detrimental than anticipated. As we look toward the third quarter of fiscal 2024 for International, as mentioned in the press release, we expect all International activity to remain unchanged across the quarter. With regard to our Middle East growth, our Galena Park facility at the Port of Houston is using its capacity to convert and recommission rigs to meet Saudi Aramco unconventional specifications for the remainder of fiscal 2024. In addition to capital investment outlined in our previous quarterly call, we are incurring recommissioning expenses. We expect to incur $10 million to $12 million of operating expense, consisting of $2.5 million of expense per rig for inspection and repair in fiscal Q3, with final recommissioning expense expected in Q4 of approximately $5 million. Also, included in the Q3 cost guidance is local office setup in Saudi Arabia of approximately $2 million. In the third quarter, we expect an overall direct margin range of a $2 million earnings to a $2 million loss aside from any foreign exchange impacts in the International segment. Finally, to our Gulf offshore Gulf of Mexico segment, we have 3 of our 7 offshore platform rigs contracted. We also have management contracts on 3 customer-owned rigs, one of which is on active rate. The offshore segment generated a direct margin of about $3 million during the quarter, which was below our guidance range as one rig was delayed in resuming full rate operations. As we look toward the third quarter of fiscal '24 for the offshore Gulf of Mexico segment, we expect to return to previous run rate levels and generate between $5 million and $8 million of direct margin. Let me update full fiscal year 2024 guidance. Capital expenditures for the full 2024 year are now expected to be at the top end of our original $450 million to $500 million range. During our November earnings call, describing initial fiscal 2024 guidance, we stated that approximately 14 walking conversions would occur in Galena Park. 7 were completed and are in the U.S. fleet, with the remaining 7 committed to the Saudi rig award. As further discussed on our last call in January, international growth capital for the 7 Saudi award also includes recertifying certain equipment to light new, conducting required modifications and purchasing specific equipment for Middle East contracts. What was previously estimated timing for maintenance CapEx across the U.S. fleet, together with refined international growth CapEx, is now pinpointed to the top end of the original range with more supply-chain clarity with our placed orders. It is worth repeating what we have said on prior calls that we are marketing our super-spec FlexRig internationally for the work they were designed for and have excelled at in the U.S., exporting these idle super-spec FlexRigs to international fit-for-purpose opportunities and increasing our fleet-wide utilization and exposing HP to markets with longer-term contract profiles and starts to reduce U.S. concentration while alleviating long idle U.S. supply. Depreciation for fiscal 2024 is now revised up from $390 million to $405 million for the full year due to the acceleration of depreciation related to excess capital spares created via the walking rig conversion program. Our expectations for general and administrative expenses for the full fiscal year are revised up from original guidance of $230 million to $240 million. This increase is due to IT project costs, as well as some other unrelated professional services and consulting fees. Research and development costs are revised up for fiscal 2024 from $30 million to $35 million due to one-time expenditures in Q2 to acquire certain intellectual property. We still estimate our annual effective tax rate to be in the range of 24% to 29%, with a variance above the U.S. statutory rate of 21% attributed to permanent book-to-tax differences and state and foreign income taxes. We continue to project an FY '24 cash tax range of $150 million to $200 million. We had cash and short-term equivalents at H&P of approximately $277 million in March 31, versus an equivalent $298 million at December 31, 2023. The sequentially decreased cash balance is largely attributable to the previously mentioned cash tax timing in Q2. There is noise from quarter-to-quarter based on timing of various payments and receipts, and movement of asset and liability balances. But overall, we are still aligned with what we projected for the full fiscal year and are still comfortable with our overall cash flow projections for fiscal 2024. That said, based on the quarter's results and our projections for the remainder of the fiscal year, we still forecast that we will be generating ample cash flow to cover our capital expenditures, the base dividend, and the fiscal 2024 supplemental dividend plan. That concludes our prepared comments for the second fiscal quarter. Let me now turn the call over to Abby for questions.

Our first question comes from Doug Becker from Capital One.

John, if you allow me to dream a little bit, it seems like the rig count is stabilizing. I'm hoping to get an update on how you view supply and demand in the super-spec market specifically. When could we potentially see pricing power again if the outlook for next year shows higher oil prices and a more favorable natural gas price outlook? I want to get a sense of the current situation and what a positive scenario might look like.

Certainly, Doug. Looking at the activity over the past several years, the super-spec segment of the market is still experiencing growth on a percentage basis. We've seen a decrease in activity for both H&P and the overall industry, mainly due to natural gas prices, as we've mentioned before. However, I remain optimistic about the outlook. The focus on driving efficiencies and reliability in a safe manner while leveraging technology is essential. That's what our customers are seeking. I'm confident about the super-spec sector in the U.S. Regarding timing, as you know, it's quite difficult to predict, although oil prices are currently strong. The gas basins have seen a significant pullback in activity, but I believe we will witness improvements 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, our outlook is really shaped by ongoing discussions with customers. We recognize the continued churn we've mentioned, but there are instances where customers have opportunities to add rigs. Additionally, there's a consistent process of high grading as we move forward. Looking at the overall rig count, we've remained within a five-rig range since June of last year. We are all aware of the challenges in the natural gas sector. Our expectations come from the feedback we've gathered in conversations with customers. As I've mentioned before, forecasting beyond a quarter can be very challenging due to various factors that can arise quickly. However, based on our current knowledge and the insights we've received, that’s the projection we've formulated.

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?

That's a great example. Ultimately, we're engaging in discussions with our customers. This is a partnership, and we work closely to understand their deliverables and what constitutes a positive outcome for them. Whatever the metric is, that’s our focus. We need to deliver wells more efficiently, save time, and improve wellbore quality and consistency. Our technology solutions are essential in achieving that. If we can establish a performance-based contract that effectively rewards the service provider, in this case H&P, and aligns with the customer’s desired outcomes, that's a true win-win situation. As we’ve mentioned, we are making significant investments. This is a capital-intensive business, and those investments are aimed at improving quality and performance. At the same time, we must achieve returns above our cost of capital; otherwise, it becomes quite challenging for us to remain attractive for investment now and in 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 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 decisions might happen?

I would like to summarize our thoughts on service intensity. We mentioned in our last call that laterals have more than doubled over the past five to seven years, and we are drilling these wells in significantly fewer days. The outcome of this is greater resource exposure, improved results, and better returns for our customers. Concurrently, our equipment is operating with increased demand. As Mark pointed out regarding maintenance capital expenditures, we are seeing those costs rise on a per rig basis, largely due to the increased service intensity. Performance-based contracts play a vital role in aligning with our customers' desired outcomes and in creating a value proposition that we are compensated for. This concept extends beyond drilling rigs to include pressure pumping and all equipment in our operations, which are all working harder to meet the demands of more complex well designs, longer laterals, and significantly quicker cycle times.

Can we discuss the Saudi rigs a bit more? It seems like there's a process for sending them over. After the operating expenses and start-up costs that Mark mentioned are incurred, do you anticipate additional similar costs in fiscal 2025, or will that be the end of it? Also, when do you expect these rigs to reach their proper run rate for revenue and margins?

Thank you for the question, Keith. Most of the recommissioning expenses will be incurred in the current fiscal year '24. As I mentioned earlier, we expect to see between $10 million and $12 million in expenses in fiscal Q3, followed by another $5 million in fiscal Q4 for recommissioning. After that, the rigs will be prepared for mobilization to the Middle East. When mobilization occurs, there will be a cash expense of $2 million for each rig, which will be deferred and recognized over the contract term, along with the associated mobilization revenue once operations begin. Most of this will be reflected in 2025 and over the duration of the contract. We anticipate that these rigs will primarily be exported before the end of this calendar year and will start operations in early 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 address that, John, and feel free to add your thoughts. There are several factors to consider, and most of our daily expenses are tied to labor. We are currently incurring some costs in the country as we establish an office and begin hiring staff. Initially, we will have a significant number of personnel from our North America Solutions segment to ensure safe and efficient launches. Over time, we plan to form local teams and share knowledge. A good example of this is Argentina, where we have been operating 8 or 9 super-spec rigs for some time without any U.S. expats present, maintaining a market share in the Vaca Muerta similar to our position in the U.S., though on a smaller scale. Additionally, we will experience supply-chain advantages as we continue our operations. We are working on equipment recertification and recommissioning at our facility in Galena Park. Once we are established in-country, we expect to benefit in a few key areas. First, since these rigs are nearly new, we anticipate minimal maintenance capital expenditures during their initial five-year contract period. Second, we will develop our supply chain within the country, aiming for local value spending. This approach should enhance our operational efficiency regarding maintenance and the procurement of materials and supplies. We are actively pursuing these initiatives and are enthusiastic about the potential to implement these strategies.

Got it. Appreciate the color. And then turning back to the U.S., the customer consolidation in E&Ps, obviously should be beneficial for H&P. 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 a distinct possibility for H&P in the near future?

I really don't want to get into those details. However, when I reflect on H&P, we've generally benefited from many consolidations over the years, and we expect that to continue. Ultimately, what matters is our ability to deliver safe, efficient, and reliable performance. As long as we maintain that and foster strong partnerships with our customers, I believe we'll be in a great position 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 bid tender environment 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 that are very different than that historical experience you just outlined.

And this is John. To build on Mark's comments, regarding Saudi Arabia, we acknowledge that it's unconventional, but we have significant experience in this area. There was a question earlier about potential additional tenders, and I believe there will be more opportunities over the next few years. We expect to be successful in securing these tenders because we will be adding value for Aramco. Another important aspect that we haven't discussed much is the technology involved in our offerings, which presents further opportunities. Reflecting on our operations in the U.S. and our experience in unconventional projects, we've seen continuous year-over-year improvements largely driven by technology. This aspect adds another layer of potential for H&P.

Mark, I wanted to ask one more on 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?

Certainly, Marc. Reflecting on fiscal '23, if we review our maintenance and capital expenditures at the start of the year, we actually did not spend as much as initially planned by the end of September 30. We experienced downward revisions and significant supply chain challenges. This year, however, we have observed improvements in the supply chain, allowing us to make up for lost time. The current amounts we are seeing are temporary as we stabilize our supply chain. The components involved include various items such as the 7-year top drive, the 5-year BOP, engine work, and mud pump work, representing a wide range of rig components. As I collaborate with our U.S. operations and maintenance teams, I can see progress on some of these components. I anticipate that the volume we are currently managing should begin to decline by 2025. However, I do expect that some inflation will persist. Therefore, I don’t foresee us dropping below $1 million, but the initial range we set for the year, between $1 million and $1.5 million, remains a reasonable estimate for the next couple of years.

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 some of these large E&P consolidations, once they are completed, you might notice some geoscientists leaving these consolidated companies or becoming redundant, and some private capital is pursuing them, leading to the formation of new companies. You may see an increase in private activity in the second half of this year or possibly in 2025. Are you noticing any early signs of that? Are you having any discussions about it?

Most of our active fleet today is with large public companies, approximately 80%. However, we have established good partnerships with private companies as well. Recently, in the past quarter, we deployed a rig for various small private firms, which I believe represents a promising opportunity. Typically, during the initial phase of consolidation, we notice a slowdown in activity. Nevertheless, these companies will aim to maintain their production levels, which often involves keeping the same number of rigs or even increasing them. We could certainly witness more activity from additional private companies, as we have seen in the past, but it's difficult to predict that with certainty.

Okay. And then just one final question, as the service intensity continues to increase now going to these 4-mile type laterals, are you seeing changes in the super-spec rig specifications, or is the super-spec rig that was preferred in the last year or two still relevant?

Very relevant. We have been able to handle these 3 and 4-mile laterals with the equipment that we have. There are times where you may need to increase 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 a 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?

Kurt, that's a very good question and one that many people are considering. There are certainly a variety of opinions on this topic. Our view is that we expect a recovery in the gas sector to happen sooner rather than later. It is clear that natural gas is a valuable energy source for many reasons, and we see significant opportunities ahead, particularly in unconventional gas resources in the Middle East. There is a market out there, and we believe there is great potential for us. However, as I mentioned earlier, it’s difficult to predict exactly when this will occur. I believe H&P will play a major role in that recovery once it begins, similar to our previous contributions before the downturn in 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, plus 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 from the H&P perspective. The rigs that we have idled over the last year are, in my view, ready to go back to work and wouldn’t require much startup expense. We are not cannibalizing our fleet, so we have available capacity. I can't say for sure what that would be right now, but I wouldn't expect a significant amount of startup capital expenditure to be needed. Again, I'm assuming this would happen in a timeframe of about one year to one and a half years from being idle to going back to work.

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.