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Good day everyone and welcome to today's Helmerich & Payne's Fiscal First Quarter Earnings Call. At this time, all participants are in a listen-only mode. Later you will have the opportunity to ask question during the question and answer session. Please note today's call will be recorded and will be standing by should you need any assistant. It is now my pleasure to turn today's conference over to Dave Wilson, Vice President of Investor Relations. Please go ahead.

Thank you, Chloe [ph] and welcome everyone to Helmerich & Payne's conference call and webcast for the first 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 turn the call over to John Lindsay.

Thank you, Dave, and hello, everyone. Thank you for joining us today. The company continued to perform well, closing out calendar year 2023, despite the persistent volatility in crude oil and natural gas prices. During the quarter, and for most of the last year, frankly, the company's stock price continued to trade, as it has historically, with a strong correlation to crude oil prices and rig count. Decoupling from these traditional commodity measures requires proving our ability to maintain returns above our cost of capital through the cycles, and I believe our fiscal first quarter results are another step in that direction. The North American Solutions segment exited the first fiscal quarter at 151 active rigs, which was at the lower end of our guidance range. We increased our rig count during Q1, but the expectations we had for incremental rig ads were tempered to some extent by the ongoing churn that we are still experiencing in the market. We added four rigs during our first fiscal quarter and expect to add another three to eight rigs during our second fiscal quarter, exiting in the range of 154 to 159 rigs. Our rig count today is at 154 rigs, so we've already added three rigs forward to-date. I'm very pleased with our North America Solutions team's effort to provide the drilling outcomes our customer's desire, drive our value proposition, and maintain reasonable margins in the face of the volatile market. During the first fiscal quarter, the company delivered direct margins that were higher on a sequential basis, indicating that our direct margins, like our rig count, look to have experienced a trough during our fourth fiscal quarter of 2023. Looking out to the March quarter, we project our North America Solutions direct margins to remain relatively stable. Now looking back, the industry super-spec rig count declined in calendar 2023, and there are a couple of things worth pointing out. First, much of the decline occurred during the first six months in the more gassy basins. The decline in the number of non-super-spec rigs was about the same in terms of the decline in the number of super-spec rigs, but the decline was double on a percentage basis, given the dwindling number of non-super-spec rigs remaining in the market. As a consequence, the number of super-spec rigs working as a percentage of the overall fleet is above 70%, illustrating that the replacement cycle and high-grading contracting behaviors continue. The second is rather a data point that helps put things in perspective from where we stand, and that is our rig count in the Permian Basin at the end of calendar year '22 was approximately 98 rigs at the end of the calendar year, and for calendar year 2023, it was approximately 96 rigs. We see this as indicative of our positioning in the market and the value we provide, as well as the nature of our customer base and their desires for better drilling outcomes. Along those lines, we see that greater demand for technology and reliability remain dominant trends in the industry. The higher specification equipment and technology of the Super-Spec fleet deliver the higher levels of performance and value required for the unconventional drilling plans that now dominate the U.S. market. And this speaks directly to a very important element within our contract economics, which is the operational costs involved in providing our services. Over the past two years, we've experienced increases in operational expenses due to rising labor costs and consumable inventory consumption and cost inflation. A less visible but growing variable is the cost acceleration on equipment related to running H&P's FlexRig fleet harder than ever before to achieve more complex well designs, lateral length, and the drilling efficiencies required from our customers. Let me expand on an example of service intensity. In the last 10 years, for H&P, the average lateral length drilled has more than doubled to over 10,000 feet. And at the same time, the well cycle times have improved by approximately 22%. This means that each FlexRig today drills approximately four and a half more wells on average per year, and those rigs have doubled the exposure per well to the resource. This performance improves outcomes for our customer, and in return, we are focused on getting appropriately compensated to drive financial returns through the cycles. Now shifting to our international solution segment. We're very pleased with the recent developments that are proof of our execution on our international expansion strategy. The company recently received preliminary notification subject to finalization of contractual agreements that it has been awarded seven Super-Spec FlexRigs for work in a drilling campaign in the Middle East. These rigs are expected to commence operations shortly after delivery, which is currently scheduled for the first half of fiscal 2025. Additionally, these rigs will be sourced from our idle Super-Spec rigs in the U.S., converted to walking configurations, and further equipped to suit contractual specifications. We believe that H&P is uniquely positioned for this award as we are able to invest in and utilize some of our high quality idle Super-Spec rigs that are available in the U.S., combined with our immense drilling experience and expertise. Furthermore, in the Middle East, we've been successful in contracting an additional rig in Bahrain. The Super-Spec rig to be utilized for this work is already located in the region, and it is expected to commence operations during the summer of 2024. These are positive outcomes in our Middle East expansion strategy, and I want to express my appreciation for the grip and determination our teams put forth to accomplish what we have to this point, and we look forward to further growth in the future. Strategically, we will continue to look for opportunities to invest in projects with attractive returns so that we maintain our industry lead in the U.S. and develop further growth internationally. In addition to operational and growth accomplishments, we believe an essential ingredient in achieving shareholder success is having a multi-pronged approach to capital allocation. First and foremost, we prioritize the company's long-standing posture of a strong financial position and fiscal prudence. Secondly, we seek to return capital to shareholders through an established base dividend augmented by supplemental dividends and share repurchases when those opportunities exist. Mark will provide the details about the progress of our plan in his remarks. In closing, every year energy industry challenges arise, many resulting from supply and demand dynamics that ultimately result in crude oil and natural gas volatility and the cyclical nature of oil and gas. As difficult as it is to manage in these times, we also find that headwinds often provide opportunities to showcase the exceptional capabilities of our fleet and to demonstrate the value our people, our technology and processes bring to providing drilling solutions for our customers. For our part, we will remain focused on our goals and execute toward their achievement in the long term. And now I'll turn the call over to Mark.

Thanks, John. Today I will review our fiscal first quarter 2024 operating results, provide guidance for the second quarter, update remaining full fiscal year 2024 guidance is appropriate and comment on our financial position. Let me start with highlights for the recently completed first fiscal quarter ended December 31, 2023. The company generated quarterly revenues of $677 million versus $660 million from the previous quarter. As expected, the quarterly increase in revenue was due primarily to sequentially higher revenues in North America Solutions segment. Total direct operating costs were $404 million for the first quarter versus $410 million for the previous quarter. This decrease is attributable to lower sequential direct expenses in the international segment. General and administrative expenses were approximately $57 million for the first quarter, which was in line with our expectations. During the first quarter, we recognized the loss of approximately $4 million primarily related to the change in the fair market value of our equity investments, which is part of the loss on investment securities reported in our consolidated statement of operations. Our Q1 effective tax rate was approximately 24%, which was at the lower end of our previously guided range for the quarter due to adjustments to our foreign tax expectations. To summarize this quarter's results, H&P earned a profit of $0.94 per diluted share versus $0.77 in the previous quarter. As highlighted in our press release, first quarter earnings per share were negatively impacted by a net $0.03 loss per share of select items consisting of the aforementioned loss on investment securities. Absent to select item adjusted diluted earnings per share were $0.97 in the first fiscal quarter versus an adjusted $0.69 during the fourth fiscal quarter. Capital expenditures for the first quarter of fiscal 2024 were $136 million, which was $22 million more than the previous quarter's spend as some items originally forecasted in fiscal 2023 CapEx moved to fiscal 2024 as expected. I will comment later on our fiscal '24 capital expenditure guidance, but we'll just state here that it is unchanged. Q1 cash flow from operations is at $175 million was higher than our internal expectations as the timing of our tax payments shifted from December to early January. As a reminder, our Q1 cash flows are typically influenced by seasonal factors such as the payment of accrued annual incentive compensation, tax payments, as well as other seasonal working capital changes. This Q1 was impacted by accrued annual incentive comp as well as increased working capital as rig activity in the North America Solutions segment was higher following the bottoming of our rig count in Q4 fiscal 2023. I will address the company's cash position later in my remarks. Turning to our three segments, beginning with the North America Solutions segment, we averaged 149 contracted rigs during the first quarter, flat from the fourth quarter of fiscal 2023 as the rig count bottomed in September and then turned up through Q1. The exit rate count of 151 was toward the low end of our guided range of between 150 and 156 as churn continued per John's earlier comment. Said differently, our modest expectations for incremental rig additions in Q1 were tempered by this churn in the market, while demand is present for Super-Spec rigs, net rig additions were lower due to new rig awards, essentially replacing rigs being sidelined due to churn. Revenues increased sequentially by $19 million, primarily due to lower price term contracts rolling the current market rates. Segment direct margin was $256 million, which is just above the high end of our guidance and sequentially higher than the previous quarter, which came in at $239 million. Performance contracts continued to make up approximately 50% of total contracted rigs in the first quarter. Total segment expenses are relatively flat at $19,600 per day in the first quarter compared to $19,800 per day in the previous quarter. Looking ahead to the second quarter of fiscal 2024 for North America Solutions, as of today's call, we have 154 rigs contracted as the rig churn has continued, resulting in their activity level gradually increasing thus far in the quarter. This is consistent with the line of sight we had for activity in November. We expect to end our second fiscal quarter with between 154 and 159 working rigs. Revenue backlog from our North America Solutions fleet remained at roughly $1.1 billion for rigs under term contract. As of today, approximately 60% of the U.S. active fleet is on a term contract. Average pricing per day should remain relatively flat up, slightly, as some remaining legacy term rate rigs roll over to the spot market. In the North America Solutions segment, we expect direct margins in fiscal Q2 to range between $255 to $275 million. We expect cost in Q2 to decline sequentially in part due to lower recommissioning expenses associated with putting active churn rigs into new contracts as opposed to idle rigs. Next to our International Solutions segment. International Solutions activity ended the first fiscal quarter with 12 rigs on contract. International Solutions results were slightly above our guidance range as an Argentina rig release was pushed back one month into the second quarter. Note that our previous guidance range excluded foreign exchange impacts, which reduced these reported results by approximately $2 million. This loss was primarily due to Argentina's devaluation of its Peso relative to the Dollar by approximately 55% in December of '23. As we look toward the second quarter of fiscal '24 for international, as we mentioned in the press release, we will idle our remaining active rig in Colombia, as well as the one rig in Argentina I previously mentioned resulting in eight active rigs in that country. With regard to the Middle East expansion, John announced earlier, the one rig award in Bahrain will utilize the Super-Spec FlexRig exported last year to our Middle East hub. This additional Bahrain rig, as well as the Saudi Arabia rig awarded in August of 23, should both start sometime in the summer of 2024. The seven Middle East rigs we were recently notified about are expected to start shortly after delivery, which is scheduled to occur through the first half of our fiscal 2025. We expect to incur approximately $4 million of operating expense in fiscal Q2 in preparation of rigs for export. In the second quarter, we therefore expect to earn $1 million to $3 million in direct margin, aside from any foreign exchange impacts in the international segment. Finally, to our offshore Gulf of Mexico segment, we have three of our seven offshore platform rigs contracted. We also have management contracts on three customer-owned rigs, one of which is on active rate. The offshore segment generated a direct margin of $6 million during the quarter, which was in line with our guidance range. As we look toward the second quarter of fiscal 2024 for the offshore Gulf of Mexico segment, we expect to be roughly flat and generate between $4 million to $7 million of direct margin. Now let me update full fiscal year 2024 guidance as appropriate. We expect the timing of our CapEx spend to vary from quarter-to-quarter. As mentioned on our November call, our original guidance included delays that continued to push some plan to maintenance CapEx from fiscal 2023 to fiscal 2024, resulting in moderately higher CapEx in fiscal Q1. Capital expenditures for the full fiscal 2024 year are still expected to be between $450 million to $500 million. As previously discussed, our 2024 guidance includes international growth capital, which is inclusive of converting idle U.S. rigs to walking, recertifying certain equipment to like new, conducting required rig modifications, and purchasing specific equipment for Middle East contract opportunities. The seven rig award notification will require $30 million to $35 million in total of additional capital in fiscal 2025. If procurement timing expectations change, then we will update guidance as appropriate in future quarters. As discussed on our November call, we planned approximately 14 walking, rig convergence in fiscal 2024. Seven of these are now allocated to the Middle East award, with the remaining up to seven to be allocated in the U.S., depending on customer demand and attractive rates and terms. As we have said on prior calls, we are marketing our Super-Spec FlexRigs internationally for the work they were designed for and have excelled at in the U.S. And as we have stated for some time, exporting idle U.S. Super-Spec FlexRig to international fit for purpose opportunities increases our fleet-wide utilization, exposes H&P to markets with longer-term contract profiles, starts to reduce U.S. concentration, and alleviates long idle U.S. supply. As previously mentioned, our expectations for general and administrative expenses for the full fiscal 2024 year remain at $230 million. We still estimate our annual effective tax rate to be in the range of 24% to 29%, with the 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 a fiscal year 2024 cash tax range of $150 million to $200 million, including approximately $90 million paid in Q2. Now looking at our financial position, H&P had cash and short-term investments of approximately $298 million at December 31, 2023, versus an equivalent $350 million at September 30. The sequentially decreased cash balance is largely attributable to our Q1 share repurchases of approximately $47 million. Approximately 1.3 million shares were repurchased in fiscal Q1 for this $47 million. Calendar 2023 repurchases totaled approximately 7 million shares for about $256 million at an average price of about $36.50 per share, which reduced our shares outstanding from the beginning of calendar 2023 by about 7%. Our calendar year 2024 share repurchase authorization has been reset to the evergreen level of 4 million shares. The fiscal Q1 stock repurchases, together with the base and supplemental dividends paid in December, resulted in approximately $90 million of return to shareholders. We expect some quarterly variability around our free cash flow generation due to rig activity, working capital changes, and the timing of CapEx spent. That said, based on this 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 capital expenditures, the base and supplemental dividends. And as we have said before, cash generated in excess of these priorities, together with excess accumulated cash on hand, is available for opportunistic share repurchases or other accretive investment opportunities. That concludes our prepared comments for the first fiscal quarter. Let me now turn the call over to Chloe for questions.

Thank you. [Operator Instructions] And we'll pick our first question from Saurabh Pant with Bank of America. Your line is open.

Hi. Good morning, John and Mark. I can't help but say congrats on a very solid quarter.

Thank you. Appreciate that.

And all around that, maybe let me start on the international side, John and Mark. Obviously, with the news out on Saudi today, the obvious question, I apologize for that, is on the end markets that these rigs are going to. I'm thinking about the seven rigs specifically. If you can give us any color to the extent you can about the end market, what kind of work these rigs would be doing oil versus gas, any color on contract duration, basically anything that you can help us with along those lines?

Well, at this stage, we really can't share anything as far as you know where the rigs are going or anything related to that. Mark, you have anything to add?

Yes. And we're, with that, I'll just suffice it to say, and I'm sure others will have questions like you, but I'll just suffice it to say that from top line economic perspective, in our models, these nine rigs in total, when operating for a full fiscal year together, will contribute more direct margin than the international segment did for fiscal 2023. We are not prepared, however, at this stage to discuss anything more in detail. Once we've finished contractual and administrative obligations related to the recent seven rig award, we will issue a press release correspondingly at that time to fill in some more of the details.

No, I appreciate that. I know it's tricky to give a lot of details, but I appreciate, Mark, your comment on the profitability. Maybe a follow-up on the North America side, I think it's really positive to see the flattish to slightly better margin guide for the March quarter. If you can help us with the trajectory after that, how should we think about leading-edge day rates or revenue per day? Where does that stand relative to your contract book? Again, you may not be able to give all the detail, but to whatever extent you can help us on that?

Yes, looking, it's really, as you know, and you've heard me say this before, Saurabh, it's hard to predict much past a quarter. We too were very pleased with Q1 and the trends that we're seeing. Salesforce has done job. Operation is doing a great job in delivering value for customers, and we're getting compensated for that. So, we feel really good about that. And as we said, our remarks flat to slightly up is our expectation there. So, we're pleased about the success and think we'll have that going forward.

I would just put a note to that, John, that, Saurabh, we do still see some term rates that are rolling off that are slightly lower than the spot, but the two have grown closer together.

Okay, I get it. Okay, no, that's very helpful context. Okay, John, Mark, thank you. I'll turn it back.

Thank you.

And we'll move next to Derek Podhaizer with Barclays. Your line is open.

Thanks. Hey, guys, I guess just another question on the international, the Saudi pause that we heard from today. I mean, I've always been under the impression that you guys are attacking more of the unconventional gas market, just given the types of rigs that you're sending over there. So I know you don't have much to say about it right now, but is that still a fair assumption that you're more leaning towards more of the unconventional gas versus some of the conventional oil that's part of these expansionary programs?

Yes, Derek, I mean, we've been talking about unconventionals and the FlexRig fleet for, gas for as long as I can remember. So that is not, that's not -- that's our strategy. That's where we're best suited to perform. So yes, I would agree with that.

Great. Appreciate that. Switching back over to the U.S., just maybe could you expand a little bit more on the revenue per day climbing higher, about $1,000 per day. Any chance you can characterize that between performance based contracts, legacy rigs being repriced higher, higher price rigs rolling off to down a closer to spot, just any example of performance based contract benefit, just a little more health and color about the actual drivers of that revenue per day stepping up?

Well, unfortunately, Derek, the $1,000 is a mix of all the above. Teasing apart any of those in a meaningful detail is not fair to the other bits, frankly. We had some term rollover up. We've had increasing Delta with the performance kickers on that half of the fleet, which is average across the entire fleet, one to 2000 per day uplift from the regular spot market, half of the fleet. So, and then, even with the above that, some technology pull through revenue on the spot, half of the fleet. So there's a mix of things in there.

Yes. And I would just add to Mark's point, it isn't all of the above. And that's really how our teams are approaching that is, they're looking at those opportunities. And, there's obviously some performance based contracts in there. We're still in that 50% range on performance contracts. In there's we're still in that 50% range and performance contract. So there is some that, and the team is really doing a great job in looking at it across the board and focusing on value for customers at the end of the day.

Got you. And maybe just a quick follow up on that. Those legacy price contracts that are stepping up, what was the prior duration on those contracts? And do you still have any of those rigs that are left?

We still have a few, we still have some, yes, rolling over this quarter. So you'll see some full effect of that. And at the end of Q2, we're talking about that in April. But then the two are really converging, I think, the delta between spot and term for us is really narrowing, a couple hundred dollars a day, really.

Got it. Thanks, guys. Appreciate the color. Thank you. I'll turn it back.

Thanks Derek.

And we will take our next question from Jeff LeBlanc with TPH. Your line is open.

Good morning, John and Mark. Thank you for taking my question. The question I have is, we've noticed that two of your largest customers on the Permian have yet to deploy any more rigs in 2024. Could you provide some color on the expected operator mix and basin mix for your incremental deployments moving forward? Thank you.

I'm sorry. If you can get closer to your microphone, we literally couldn't hear you at all.

Jeff, did you hear us? We couldn't hear the question.

I'm sorry. The quick question was, we've noticed that two of your largest customers on the Permian have yet to deploy incremental deployment in 2024. Could you provide some color on the expected operator mix and basin mix for your incremental deployments?

Jeff, I don't have any of those details and really wouldn't be in a position to share those. I'm not certain who those customers are, but I think in general, again, for us at H&P, we're pleased with our customer mix. We've got very strong customers and some have been, well, first of all, they're all being very disciplined in their approach. I think that's -- as I've said before, that's great for the industry. So I think several have maintained their rig counts pretty flat through the course of the year. There's a few that are planning on adding a rig here or there. And of course, that's what you've seen with our rig count, just a very modest rig count increase in our Q1, and we're forecasting that for Q2.

I would just put a note that, we're now, as John mentioned, good customer counterparties, and we're up to 80% of our U.S. fleet with public companies, and three-fourths of that is with large public companies. And with many of our top customers, we're their largest provider and in half-term coverage, so we just add those little footnotes. Jeff, any other questions?

No, that was it. Thank you very much, and I'll hand it back to the operator.

And operator just real quick, I want to correct something for Derek a minute ago. I said $200. I mean $2,000 today in that delta between spot and term. That's what we're down to. Back to you, Chloe.

Thank you. We'll move next to Doug Becker with Capital One. Your line is open.

Thanks and congratulations on the international contracts. I know that's been a long time in the works.

Thank you, Doug. It has been.

I was hoping just to get an update on the costs around the conversion, contract prep, and mobilization costs for those seven rigs, and really kind of thinking about it in the context of, does this mean like the CapEx probably in the upper half of the guidance range, or is the midpoint still the best point estimate at this point?

Well, we're still leaving it at a range, Jeff, because as you know, the timing of procurement items always varies from quarter-to-quarter. Having said that, if you take the original guidance we had in our October capital allocation press release and then November call in the associated release at that time for the end of fiscal '23, looking forward to this fiscal year we're in, we said a third of that would be related to the international. So if the midpoint is 475, you have a number there, and then if you add to that what I just mentioned in my prepared remarks, another 32 million in fiscal '25, you add all that up all in, you're at about 25 million to 28 million per rig investment. And again, that covers a myriad of things as you just alluded to, the conversion to walking, basically recertifying all equipment on the rigs to like new, so they have full recertification run rates for API standards, et cetera., buying certain equipment incremental for the contract needs and certain rig modifications as well for those contracts. But all in, that's the number we're looking at, which is from our understanding quite a significant delta less than what would be required for any such new build to go to the region.

Okay, and kind of putting that together, does this imply that the initial free cash flow outlook of say $235 million for the fiscal year, and I know there's a lot of moving parts here, but it sounds like that will be a little bit lower than initially expected, just given the this spending?

Now all of our guides related that since we have not changed the capital expenditure guide, I can't really foresee an overall implied guide either related to cash in the supplemental dividend plan, with the potential exception of rig commissioning and preparation operational expense in international segment, I mentioned four million that we're planning for this Q2. I think that might be a good run rate for the rest of the rest of the fiscal quarters moving forward, but to be determined we have we'll be back to you with more guidance as we move through the year on that.

Got it. Mark, I appreciate it.

Thank you, Doug.

And we'll take our next question from Waqar Syed with ATB Capital Markets. Your line is open.

Thank you. So, John, you're picking up between three to eight rigs in the quarter. Do you think you're getting market share or if we apply like a 25% mark, 25% market share, if you maintain that, then that means the industry's rig can't go up by between 12 and 30 rigs by the end of the March quarter. So how do you see the industry's rig changing through the course of the quarter?

Good morning, Waqar. I don't have a good feel for the overall industry. I mean, your numbers are accurate as you've described them. I do think there are a couple of cases where there's some high-grading that's going on with some of the rigs that were picking up, but I don't have a sense for how the rest of the fleet, in terms of the super-spec fleet and our competitors, my assumption is that they'll be adding some rigs as well, but I don't know that. I do know that, as I said on the replacement, the super-spec, pardon me, the non-super-spec fleet rig count is down, and a larger percentage actually doubled the percentage of the super-spec over the course of the last year, and really a lot of that has happened recently. So we're seeing that replacement cycle continuing. So, from a market share perspective, you've heard us say that's really not our focus. Our focus is just making certain that we're getting compensated and getting the returns above our cost of capital is really the primary focus here. So hopefully that helps.

It's helpful. Also, like, the service intensity of drilling in the U.S. continues to increase. You have at least one company saying, they're looking for formal laterals. Historic definition that we've used for super-spec, 15 and horsepower AC, like, 7500 PSI circulating systems. Those definitions still hold up for this high-end kind of drilling? Or do you think that there's another subset of super-spec rigs that is going to be created to do the next generation of high-intensity drilling?

Yes, I believe that our current fleet, in fact, we have our FlexRigs today, drilling four-mile laterals. There's not a lot right now, but we do have rigs, some of our rigs, drilling four-mile laterals. So the rig, the super-spec-based rig, in most cases, there are a couple of depending on hookload requirements and those sorts of things, but in general, we've been able to cover with our fleet. I can't speak to the overall industry super-spec fleet. My assumption would be that, there's going to be a mix of some of those rigs we're going to be capable of doing the four-mile laterals. But, again, more to come on that as far as just how much of -- how many of our customers actually go to the four-mile.

Sure. And just one last question for your international contract, these seven rigs, the eventual contracts are going to be five years or three years, or how long would the duration be?

There will be more to come on that when we file our press release. It'd be best just to put all that information in there together.

And just on the investment, did you say 25? What's the total investment on a rig? Is it $25 million? But there's certainly a original cost as well that you're carrying the books for the rigs?

I'm sorry, Waqar, could you say that one more time?

Well, for the seven rigs in the international markets, when you think about them as an investment, is it like a $40 million type rig investment, or is it the $25 million number that I think you previously said in terms of investment on the rig?

The previous. We're looking at the incremental investment from what has been taking long-idled super-spec rigs in the U.S. and putting them back to work.

Okay, great. Thank you very much.

From a return perspective, Waqar, we're looking to achieve returns through these contracts that are above our cost with average of capital, obviously, in line with our strategy overall related to ROIC for the corporation.

Fair enough. Thank you, sir.

Thanks, Waqar.

And we will move next to Don Crist with Johnson Rice. Your line is open.

Good morning, gentlemen. I wanted to ask about the performance contracts. To my knowledge all of the only contract out there currently doing these. And just out of curiosity, are you setting kind of days to drill per well and then kind of splitting the spread cost if you achieve better than that? Any kind of parameters you can give around these performance contracts, because it looks like you're actually making more on these performance contracts for both parties, then you would be in a spot market rate kind of just charging a day rate perspective. Any kind of color you can give around the performance contracts would be helpful?

Sure. Good morning, Don. The idea, first of all, there is no one size fits all. There is multiple types of performance based contracts with our customers. But the point is to set them up such that we're delivering what customers are seeking to achieve and there's a wide range. But at the end of the day, it's meant to be a win-win. And so, we went in that. We're getting higher margins per day, but the customer is winning because they're lowering days and/or other parameters that they're focused on. And so again, it's a true win-win. And yes, we are, I think for the most part, making more on the performance based contracts than we are on the standard contracts.

Yes, one to two thousand per day when averaged across the entire fleet, that's 50% of the fleet that's on one. And in addition to those spread cost savings, we have other, as John mentioned, actually no two were alike. Customer to customer depends on what their value driving needs are. And for some of those, it started to spread cost savings. Some of those, it's now a consistent repeatable cost per foot. For some, we actually have qualitative metrics now related to wellbore quality and placement, which we've long discussed as a company on these calls, which is exciting to see those more quality based instead of time based KPIs. But there's a portfolio approach. And when you average them out, it's $1000 to $2000 more than spot as I said.

And we've been, as you said, we've been at this a long time. This has been a three, four year process. And again, our teams are just doing a fantastic job and continue to find ways to deliver value and work very closely in partnership with our customers.

And just as a follow up to that, I'm assuming you're not taking additional risk like geologic risk if the rig, if the well doesn't work or something like that when you're forming that contract, right? .

No, there's no downhole risk at all.

Okay, so they're still directing you as to where the place and all that sort of stuff. It's just more of a generally performance based. And if you're better than a threshold, then everybody makes more money in essence?

That's one way to think. Yes, this is not a turnkey type construct contract. But I mean, there is the potential that you're, for us that we would earn a lower revenue per day. But there's the upside of the higher revenue per day, and obviously, based on what Mark said, we're in that $2000 to $4000 a day range for those rigs that are using performance based contracts.

I appreciate the lifting the veil on that some for me. I'll turn it back.

All right, Don. Thank you.

And we'll move next to a Kurt Hallead with Benchmark. Your line is open.

Hey, good morning everybody.

Good morning.

Hey, I just wanted to get a little bit clarity on your guidance dynamics for the fiscal year 2024 as it relates to your U.S. land rig count. So if I understood the press release correctly, you suggested that your activity could be moderately higher in fiscal '24 than it was in fiscal '23. And if that math is correct, then I think you average something along lines of close to 160 rigs in fiscal '23. So do you think then in that sense, you're going to average more than 160 rigs running for all of fiscal '24? I just want to make sure I was clear on that.

Yes, it's we were modestly climbed up in the Q1. We just finished and in Q2 we just guided a little higher, 154 to 159, as we said. And if you look at that and it's flat for the rest of the year, then it's we'll just let you get that average.

Yes, I guess that's why I was asking, because the average is like 154 or so for the full year for fiscal '24. It looks like fiscal '23. If my math is right, it might be wrong. The average 170 rigs in fiscal '23, so that's why I just look at it.

Yes, Kurt, that's a great point. We're talking about the back half of 2023, not full 2023. We don't have that front end. I mean, gosh, our rig count was 187 rigs or something like that during that period of time. So it's the back half of 2023. And just to be clear also, we're not giving a full year guidance. We're just saying this, what we expect in Q2. And then if you just look at historically what happens in Q3 and Q4, we're trying to match up with that. But we're not giving any guidance for Q3 and Q4.

Okay. Yes, thanks for clarifying that. Appreciate that. So on the Middle East opportunity set, right, so again big win, big number of rigs, and it looks like it's coming in a pretty short order. Without given a specific number or whatever, you think there's opportunities continue to scale that throughout 2025 with additional contracts? Or is it here's a chunk, let's see how you do and then we'll revisit sometime in fiscal '26?

Kurt, obviously, we would love to be able to say we believe there will be more. I mean, obviously, it's hard to say that. We're going to do our best to participate in opportunities in the future. We're not finished. We hope, in any respect. So hopefully we'll see more of these and more success in the future.

Okay, but I guess fair to assume off that, John, that there's nothing imminent to suggest there's going to be another immediate pop. It's going to be some progression over time. But it really was trying to get to was is this a dynamic where you haven't really operated at scale in the Middle East and probably in this particular country, though you have plenty of track record in what you can do in the U.S. So, it's not like you're a startup or anything. But maybe this customer is like, look, we're going to give you a shot. We'll give you a chunk of work. Let's see how you do. And then we'll kind of revisit at some point time in the future. So I'm just trying to get sense of, if that's how they're looking at it, or it's, hey, man, here's trunch one and let's continue discussions and see if we get the trunch two?

I can't speak at all about what the customer is thinking. I know from -- obviously from our perspective, and you've heard us talk about this for quite some time. We have a an opportunity, we think we can we can do more, so hopefully that that will be the case. Hopefully we'll be able to be successful in the future in this. We're not finished with this.

That's all. Fair. Thanks, John. Appreciate it.

All right, Kurt. Thank you.

And it does appear that there are no further questions at this time. I would now like to turn it back to John Lindsay for any closing remarks.

All right. Thank you, Chloe. I really appreciate everybody joining us today. We've mentioned several times on the call this morning that we remain optimistic about the long term energy fundamentals and the opportunities that this provides H&P to deliver returns above our cost of capital through the cycles and create value for shareholders. So again, thank you for joining us today and now we'll sign off. Thank you.