Helmerich & Payne, Inc.

call a webcast for the first quarter of fiscal year 2023. With us today are John Lindsey, 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 up 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 security laws. Such statements are based on the 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. 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 good morning, everyone. We are very pleased with our quarterly results and remain optimistic about the year ahead. Our first Fiscal quarter results of 2023 showed another strong sequential improvement in financial performance and a continuation of the momentum established in fiscal 22. We remain focused on our three strategic objectives, which are North America's solutions pricing and margin cycle dynamics, H&P's international opportunities, and our investments related to technology and sustainability. Almost a year has passed since we set into motion plans to achieve revenue per day in excess of $30,000 and direct margins of 50% in our North America solutions segment. These financial guideposts were established as proxies for what is required to generate sustainable levels of economic return in this capital-intensive business. This recent quarter marks a milestone in achieving that revenue per day goal as our average revenue per day was $33,000. Our per day direct margins were approximately 47%, very close to achieving our direct margin goal but still earning the highest margin level since 2014. This headway, achieved in just a year, generated significant value for shareholders. On our last earnings call in November and subsequent discussions with investors, we laid out our expectation for a moderation and activity growth for both H&P and the industry rig count during the December quarter relative to what we have seen over the last two years. That expectation is being realized and is largely attributable to the capital discipline exhibited by our customers and their desire to drive more consistent and sustainable shareholder returns. We've seen time and again that in a highly cyclical industry like oil and gas, losing sight of the long run can be fatal. So we believe that capital discipline contributes to the overall economic health of our company as well as our industry. Most of our large public customer budgets appear to be moderately higher in 2023, and we are planning ahead to manage this potential growth in an optimal fashion. Accordingly, we intend to maintain our plans for adding no more than 16 incremental rigs to our North America Solutions rig count during fiscal 23, dependent upon customer demand and would expect contractual churn to satisfy other points of rig demand. There has, however, been a change in the maximum number of rigs we can now achieve with 16 incremental rig adds. Previously, that number was 192, but is now 191 rigs due to losing an active rig as a result of a rig fire during operations. Thankfully, no H&P employees were injured during the incident. We were able to quickly respond and utilize one of the 16 incremental rigs as a replacement for the rig that was lost. Hence, the maximum number of active rigs we could reach in fiscal 23 is now reduced to 191. During our earnings call in mid-November, we mentioned having 11 of these 16 incremental rigs committed, and today we have 12. Ten are currently working, and the remaining two are contracted to begin work in February and March. The four uncommitted rigs will not reactivate without contracts, which include margins and term commitments that justify their deployment. To be clear, if we can't achieve those objectives, our preference would be to allow rig churn and spot market pricing to satisfy incremental rig demand. In light of this, here are three industry data points to keep in mind. First, utilization of the active super spec fleet is currently over 80%, a level which is supporting current pricing. the idle SuperSpec fleet has now been inactive for over three years, making reactivation an expensive proposition. The third point is that there are roughly 520 SuperSpec rigs operating currently, which is effectively 100% utilization for those rigs that have worked sometime in the last three years. Accordingly, we expect the current utilization of the active SuperSpec fleet to remain at very high levels. With our expected rig count, we anticipate financial results in the second quarter to continue on an upward trajectory with direct margins per day moving closer towards our target level of 50%. While some may be concerned with the momentum of the current cycle, our experience over the past few decades is that we should expect to have moderate and choppy activity trends like today. An upcycle is rarely straight up and to the right. Another opportunity for us during the next few quarters is having more of our fleet with long-dated term contracts roll over to current market pricing. Bringing the pricing of those rigs in line with the rest of the fleet will have a positive impact on our pricing and margin objectives going forward. Regarding the international solution segment, The company's expansion efforts are centered around unconventional drilling, where H&P has significant experience drilling unconventional wells, given that our FlexRig fleet has drilled over 30,000 horizontal wells in the U.S. over the past 10 years. This extensive experience can provide substantive value to customers with a complement of people, processes, rigs, and technology. We are moving forward on several fronts to set the company up for future growth. Efforts to grow our Middle East presence continue with the pursuit of additional work in the region and our operational hub, which should be stood up during the last half of fiscal 23. Preparations to send a SuperSpec rig to Australia for an unconventional gas play in the Beetaloo Basin are well underway. These international unconventional plays provide a great opportunity for H&P to locate SuperSpec flex rigs in the Middle East and other unconventional growth areas without the need to build new rigs. These rigs and our capabilities provide a great opportunity to utilize the idle flex rig capacity and showcase our technology to grow our international footprint. Our offshore Gulf of Mexico segment remains a steady, reliable contributor to the company's overall financial performance. That said, we are expecting some variability later in the year as we do have one rig contract that is set to expire during the fourth fiscal quarter. On the technology front, we continue to experience a growing appreciation for our technology solutions, which are adding significant value for our customers through rig efficiencies and wellbore quality. Many of our technology products and automation solutions have become integral parts of the bid process and daily operational workflows. Our operational and technology teams are delivering outstanding results for customers. Longer laterals and more consistent target attainment continue to be key themes for our customers. To achieve both, we have seen increasing usage across our technology portfolio with automation driving consistent three plus mile lateral delivery. This trend is not limited to one customer or one basin, but rather is becoming the way we work and deliver value. We believe this type of repeatable, reliable performance will continue to drive the adoption of H&P technology by our customers, as well as expand our revenue growth. This keeps our teams excited about the future, a future where digital technology helps drive customer value by providing safer, more efficient, and repeatable drilling operations. Maintaining a fiscally disciplined approach to our business is a key tenet of our long-term strategy and is a major driver behind the company's improving financial results. Mark will provide details in his comments regarding our capital allocation efforts to date for 2023, but we are pleased with the execution to date for our supplemental shareholder plan and opportunistic share repurchase efforts. In conclusion, we remain optimistic about the outlook for 2023 and the longer-term energy macro fundamentals. I've had meetings with some of our most active customers this quarter, and I'm very pleased with what I have heard regarding the value proposition H&P provides, the pride of the H&P team, and the differentiated results we helped to deliver. As a result of the hard work and dedication of our employees during this past year, We are positioned to respond effectively to healthier industry conditions and improve the profitability of the company. Working closely with customers to identify and then provide industry-leading drilling solutions, we are creating value for these customers and we're beginning to receive commensurate compensation for the value we help create. We will carry this mindset forward to the benefit of both customers and our shareholders. And now I'll turn the call over to Mark.

Thanks, John. Today, I will review our fiscal first quarter 2023 operating results, provide guidance for the second quarter, reiterate full fiscal year 2023 guidance as appropriate, and comment on our financial position. Let me start with highlights for the recently completed first quarter ended December 31, 2022. The company generated quarterly revenues of $720 million versus $631 million from the previous quarter. As expected, the quarterly increase in revenue was due primarily to focused efforts to move our average North America fleet pricing toward recent leading-edge rates. Total direct operating costs were $429 million for the first fiscal quarter versus $412 million for the previous quarter. The sequential increase is attributable to slightly higher average active rig count in North America and a full quarter of the labor-related increase discussed on our November call. General and administrative expenses were approximately $48 million for the first quarter, slightly lower than our expectations. During the first quarter, we recognize the loss of $15 million, primarily related to the fair market value of our adenoch drilling investment, which is reported as a part of loss on investment securities in our consolidated statement of operations. We also decommissioned eight non-superspec rigs in Argentina and incurred approximately $12 million in impairment charges primarily related to those Argentina rigs. Our Q1 effective tax rate was approximately 25%, which is within our previously guided range. To summarize this quarter's results, H&P earned a profit of $0.91 per diluted share versus $0.42 in the previous quarter. First quarter earnings per share were negatively impacted by a net 20 cent loss per share of select items as highlighted in our press release, including the aforementioned loss on investment securities and impairment charges. Absent these select items, adjusted diluted earnings per share was $1.11 in the first fiscal quarter versus an adjusted 45 cents during the fourth fiscal quarter. Capital expenditures for the first quarter of fiscal 2023 were $96 million, Similar to fiscal 2022, we expect the timing of our CapEx spend to vary from quarter to quarter. H&P generated approximately $185 million in operating cash flow during the first quarter of 2023, which was generally in line with our expectations. I will have additional comments about our cash and working capital later in these prepared remarks. Turning to our three segments, beginning with the North America Solutions segment. We averaged 180 contracted rigs during the first quarter, up from an average of 176 rigs in fiscal Q4. We exited the first fiscal quarter with 184 contracted rigs, which was in line with our guidance expectations. Revenues increased sequentially by $75 million due to higher average pricing, as mentioned earlier. Segment direct margin was $260 million at the midpoint of our November guidance, and sequentially higher than fourth quarter fiscal 22's $204 million. In addition, reactivation costs of $8.6 million were incurred during Q1 compared to $7.5 million in the prior quarter. We had eight net reactivations in Q1, including a ninth reactivation that replaced the rig lost in the fire that John mentioned earlier. First quarter reactivation costs were related to the deployment of those nine rigs, as well as preparation costs incurred on rigs ready for being ready for deployment in the first few months of calendar 2023. Total segment per day expenses, including recommissioning costs and excluding reimbursables, excluding recommissioning and excluding reimbursables, increased to $16,800 in the first quarter from $16,500 per day in the fourth quarter. This is broadly in line with expectations, primarily due to the previously mentioned labor-related increase that commenced at the beginning of the fiscal year. Looking ahead to the second quarter of fiscal 2023 for North America Solutions, as I mentioned earlier, we ended Q1 at the midpoint of our exit guidance range. The activity level looks to continue to grow, albeit at a more moderate pace than the first quarter, driven in part by public company operators who are working to fulfill their calendar 23 budget levels. As of today's call, we have 185 rigs contracted and we expect to end the second fiscal quarter of 2023 with between 183 and 188 contracted rigs. Just to be clear, in revisiting John's comments on our rig count, we have previously stated that we could add up to 16 rigs and that would get us to a maximum of 192 rigs during the fiscal year. Due to the loss of the one rig to a fire, that maximum number is 191. So since fiscal year end through today, we have added 10 of the 16 for a net add of nine rigs, with another two slated to go to work over the next few months. Our current revenue backlog from our North America Solutions fleet is roughly $1.1 billion for rigs under term contract. As of today, approximately 55% of the U.S. active fleet is on a term contract. As mentioned in our last call, leading edge revenue per day was and still is approximately $40,000 inclusive of performance bonus opportunities and technology utilization. By comparison, our average spot revenue per day is currently in the high 30s compared to the Q1 overall average revenue per day of approximately $33,000. This provides us with a line of sight for further increases in average revenue per day over the next few quarters. In the North America Solutions segment, we expect direct margins in the fiscal Q2 to range between $280 to $300 million, inclusive of the effect of about $4 million in reactivation costs. As discussed on a November call, we increased field labor-related rates to respond to market conditions at the beginning of fiscal 2023. Labor is approximately 75% of daily operating expenses. We have also experienced increases in maintenance expense due to pricing inflation of consumable materials and supplies inventory. We believe that our current labor and materials and supplies costs will be relatively stable for the balance of fiscal 2023, resulting in higher margin accretion as average pricing for the fleet is expected to continue to move towards the leading edge. Regarding our international solutions segment, International Solutions business activity increased by one rig to 13 active rigs at the end of the first fiscal quarter. We added a rig in Argentina as expected, which brings our working rig count to nine in that country. International results came in above guidance primarily due to delayed timing for costs associated with developing our Middle East hub, including rig preparation and exportation costs. As we look toward the second quarter of fiscal 23 for international, We will incur costs to reactivate a rig in Bahrain, which we expect to begin working in the middle of the quarter, bringing us to two of three rigs working in that country. In the second quarter, we expect to earn $7 to $10 million in direct margin, aside from any foreign exchange impacts. Turning to our offshore Gulf of Mexico segment, we still have four of our seven offshore platform rigs contracted, and we have active management contracts on three customer-owned rigs, two of which are on active rate. Offshore generated a direct margin of $9.5 million during the quarter, which was in line with our estimate. As we look toward the second quarter of fiscal 23 for the offshore segment, we expect that offshore will again generate between $8 to $10 million of direct margin. Now I look at activity in other. You might have noted the increase in our other line this quarter. This was primarily due to an adjustment in our captive insurance company. At the start of fiscal 2020, we elected to set up a wholly-owned insurance captive to finance the deductibles for our workers' compensation, general liability, automobile liability, and medical stop-loss insurance programs beginning October 1, 2019 forward. Our operating segments pay monthly premiums to the captive for the estimated losses based on external actuarial analysis of historical losses and operating trends. This results in a transfer of risk from our operating subsidiaries to the captive for the deductibles, which mirrors our self-insurance retention. Insurance premiums are included in operating segment expenses and are included in intersegment sales in the other non-reportable segments. The intercompany premium revenues and expenses are eliminated in consolidation. For the three months ended December 31, 2022, the actuarial estimated underwriting expense was less than recent run rate as revised developed claim losses were less than reserved. These were adjusted accordingly, creating a positive benefit in the first quarter and other segments. Now let me look forward to the second fiscal quarter and update full Fiscal Year 23 guidance. Capital expenditures for the full fiscal 2023 year are still expected to range between $425 to $475 million with the remaining spend to be incurred over our last three fiscal quarters. Our expectations for general administrative expenses for the full fiscal year have not changed and remain at approximately $195 million. We are still estimating our annual effective tax rate to be in the range of 23 to 28%, with the variance above U.S. statutory rate of 21% attributed to permanent book-to-tax differences in state and foreign income taxes. We continue to project the fiscal year 23 cash tax range of $190 to $240 million, of which, as mentioned in November, a portion relates to fiscal 22 income taxes to be paid in this fiscal year. Now looking at our financial positions. Helmer & Payne had cash and short-term investments of approximately $348 million in December 31, 2022 versus an equivalent $350 million at September 30, 2022. Including availability under our revolving credit facility, our liquidity remains at approximately $1.1 billion. The sequential flat cash balance is largely attributable to our recent share repurchases, seasonal cash outlays, and working capital lockup, which is driven by higher revenue. Our planning shows cash generation and build in the second half of the fiscal year. As a reminder, our general preference is to maintain a minimum of approximately $200 million in cash and short-term investments. The cash and equivalents of $150 million above that minimum, plus the $100 million free cash flow we expect to generate after CapEx and after the base and supplemental dividends, as discussed on our November call, equals $250 million of flexibility for various capital allocation considerations, including accretive investments and returns to shareholders. During the latter half of the first fiscal quarter, we saw a combination of excess liquidity and an attractive opportunity to repurchase some of our shares at prices that we believe to be value-accretive. Approximately 844,000 shares were repurchased in December for approximately $39.1 million under our Evergreen annual share repurchase authorization of 4 million shares per calendar year. Note that the Board authorized the repurchase of an additional 1 million shares in calendar 2023, bringing the total calendar 2023 authorization to 5 million shares. In calendar 2023 through January 27, we have repurchased approximately 434,000 shares for roughly $20.5 million. So fiscal 2023 repurchases have totaled approximately 1.28 million shares thus far for about $60 million and augment our longstanding base dividend and our fiscal 2023 supplemental dividend. Each of these items, Stock repurchases and the base and supplemental dividends encompass the new shareholder return model that we announced in October. These actions, combined with our improving financial performance, demonstrate our focus to not only increase the financial returns of the company, such as return on invested capital, but also cash returns provided to shareholders. That concludes our prepared comments for the first fiscal quarter. Let me now turn the call over to Nikki for questions.

Thank you. At this time, if you would like to ask a question, please press the star and one on your touch down phone. You may withdraw your question at any time by pressing the pound key. Once again, to ask a question, please press the star and one on your touch down phone. I will take our first question from David Smith with Pickering Energy. Please go ahead.

Hey, good morning. Thank you for taking my question. Hi, David.

Morning, David.

John, I'm curious if you could tell us what you've been hearing from customers in gassier basins, you know, particularly, especially the privates, you know, and how the prospect for, you know, potentially sustained low U.S. natural gas prices might factor into, you know, your expectations for the trajectory of the U.S. rig count this year.

Sure, David. Well, I'll start with, we've got about 15% of our fleet that's currently working that is in just natural gas basins. And about half or a little over half of those 15% are on term contracts. From a customer perspective, we really haven't heard a lot in terms of Rig activity, obviously they're not adding. There have been rigs that we've actually added recently, both in the Hainesville and in the Northeast. But so far we haven't heard really much discussion. Again, I don't know what to expect at this point. Again, our exposure is pretty low. I think the other one of the things that's a benefit over time is the ability to move those rigs pretty easily from one basin to another. We have several of our customers that obviously have exposure in oily basins as well. So they could just as easily move one of those rigs to an oil basin.

And John, I might just add a footnote there that of our 185 active rigs, we have around 28. that are drilling gas wells, which is about 15% of the fleet, and most of those 28 are actually on some form of term.

Great. I appreciate that. And then the follow-up, if I could, you've shown strong leadership on pricing and capital discipline as the rig count increased, and we're clearly seeing the benefits of your return-focused approach. I was hoping you could to share some color on what the playbook for this, you know, returns-focused approach might suggest, you know, in this scenario, you know, if rigged demand were to come down 5% or 10%.

Yes, David, you know, it's interesting. First of all, we are focused on moving the margin, and we've said now for several months that our focus has been on getting the average closer to the leading edge, more towards the high 30s. Because we're on the lower end of that now, we want to continue to push on that. And that's important. I think the other thing that I would mention about, and I addressed a little bit of it in my prepared remarks, as it relates to up cycles. As I think back and I look back on rig activity through the up cycles, it tends to be choppy. you know, we've gone through, if you just look at the last couple of decades, you know, look at the activity coming out of the financial crisis and the pickup in activity and then the choppiness and actually, you know, having 100 rigs or more go down. Of course, we had, you know, quite a bit more rigs running then, but on a percentage basis, it's very similar. And so, I think as long as the The rig choppiness, if the rig releases are moderate, and 20, 30, 40, 50 rigs, I mean, it's a very small percentage of the overall working fleet, even if you're just looking at the super spec fleet. I know at H&P, our focus will be continuing to focus on pricing, and our teams, our sales force does a great job with rig churn and getting rigs put back to work. Sure as heck doesn't make a lot of sense to get into a bidding war. So that would be our approach, is to continue to focus on the value creation that we're delivering for customers and getting paid a commensurate amount of money for that. Really appreciate that, caller. Thank you. Thanks, Dave.

And we will move next with Saurabh Pant with Bank of America. Please go ahead.

Hi. Thank you, guys. John, a quick follow-up, if I may, on the prior question, right? I'm not trying to put words into your mouth, right? But it seems to me what you are indicating is that some kind of a 2030-40 rig decline is a relatively small number, obviously, right? And in that kind of a scenario, you would focus on pricing, and you might be willing to lay down a few rigs. First thing, I mean, is that the right characterization? Did I put that correctly from an expectation standpoint? I know it's all hypothetical at this point.

Well, yes. And again, I think I would encourage you and others to look back on previous cycles and just look at how choppy the rig count is. And I look back in the pricing from 2011 through 2014. There was a lot of volatility with rig count, and we were able to continue to maintain pricing. Obviously, we were continuing to build new rigs. There was a replacement cycle going on as well. But yeah, there's no reason to adjust your pricing on 2% or 3% or 4%, even 10% of the working fleet being idled. I mean, just historically. When you've got utilization levels above 80%, you've got pretty strong pricing power.

I would just add, Sirab, that we are not predicting a 20 to 40 rig decline. That's not what we're saying. What we're simply saying is, as John said in his prepared comments, 520 super specs working. And David's question was if you lost 5 or 10% of that, I mean, that's 26 to 52 rigs, but that's still 95 to 90% utilization of the super spec fleet. And as John just mentioned, we've historically always had pricing power above an 80% capitalization level.

Yeah, I was responding to your reference to if there were, but we're sure not predicting that. We don't.

Yeah, no, I get it. It's all hypothetical at this stage, right? But again, that's what investors are thinking about. So I wanted to make sure we understand how you're thinking about things. Yeah. Okay, perfect, perfect. And then last quarter, Mark, I think you had this in your prepared remarks that for the next couple of quarters, you expect about a $1,500 increase in average contracted revenue per day. Just if you can quickly refresh us on that, because obviously the number of rigs under contract has gone up. So if you can refresh us on that, how should we think about that number moving up over the next couple of quarters?

Sure, Rob. I think it says we said last quarter going to be the same this quarter, more or less. If you think about, you know, for us, if you look at our term fleet, I think our average day rate around the term fleet today is around $32,000 per day. And if we look at what we expect this quarter for our average spot revenue per day, That's closer to the 38.5. And then if we look at the leading edges, as I mentioned, the revenue per day, not just day rate, but revenue plus ancillary services, technology, utilization, that's just above 40.

Okay, okay, perfect. Okay, Mark, thanks for that. John, thank you. I'll turn it back.

Okay, thank you.

And we will move next with Waqar Syed with ATB Capital Markets. Please go ahead.

Thank you for taking my questions. You know, first of all, you know, if you look at the DAX inventory in the Permian, it's at a very low level right now. Are you seeing anything from your customers that they feel the DAX inventory is low and they have to build up the drilling inventory?

Good morning, Waqar. You know, we don't get into a lot of discussion on ducks, but I think just generally speaking, I think we all recognize that we're at record lows and that there are some discussions related to being able to build that duck count back up. But it's not a metric that we're following too terribly close. Dave, do you have any additional color on that?

Yeah, John, like you said, as much as we've tracked

But clearly, they're very, very low levels, and I've heard various customers talk about building those up.

Yeah, great. And then, you know, if you look at the capital spending budget of $425 to $475 million, that's a wide range. And, you know, what would drive the lower end? Is it just the U.S. rigs?

that you don't get to about 16 or is it more international that gets you to between move between the lower end and the upper end oh car thanks for the question you know a lot of that is timing i mean think about the midpoint of the range 450 if you divide it by four you probably would have expected a higher number in the calendar q1 that i mean the fiscal q1 calendar q4 we just exited but these things are lumpy i mean there's some large purchases like drill pipe orders etc if they If delivery moves a week, you can move quarter to quarter. And that really timing is what I'd say is kind of a primary factor there.

Okay. And then just one final question. You know, if I look at your rigs in the Hainesville, is there anything in terms of the capabilities which would, you know, what required them, some kind of upgrades or anything like that before you can put them to work in the Palmian or Eaglefoot?

No, WACAR, they're ready to go, essentially have the same BOPs, same layout. Those rigs are consistent across the fleet. They would be able to go pretty seamlessly over to work in any oil basin, including the Permian. Okay, great.

Thank you very much. Thanks for the color.

Thanks, WACAR.

We'll take our next question from Scott Gruber with Citigroup. Please go ahead.

Yes, good morning. Good morning. One question just on the guidance, just so I understand it a bit better. You mentioned the potential for a 7% to 15% improvement in daily margin. What drives the high end versus the low end? Is the high end, does that align with seeing the 188 rigs go to work? Do you just have more rigs at that more elevated spot rate versus the lower end? Or are there other factors that drive the delta?

Scott, thanks for the question. You know, our, our margin accretion is just, is a continual, you know, we've talked about it just as a question a minute ago, the re the moving up of the term rollovers through time and that pricing, uh, spot continuing to, you know, is not at leading edge either. We, uh, we're very, we have relationships with our customers. We don't just increase week to week, you know, it's pad to pad or quarter to quarter, some sort of periodicity. So we still have upward momentum in the spot towards leading edge as well. It's just that continual repricing all the while managing our expenses very closely so that we get the full benefit to the bottom line of that pricing increase. And we're back up to, what, 42%, I think, of the fleet on performance contracts, which helps to drive that revenue per day over headline day rates as well.

Gotcha. Yeah, I just didn't know. I mean, I know that there's a momentum to the margin expansion. I'm just trying to think about what would drive the high end versus the low end. But maybe turning to that last point you made on the performance contracts, there does seem to be more appetite to kind of go long on great contracts, certainly in a sense, you know, late last year. Do you feel like there's, you know, good continued momentum or maybe even great momentum today on performance type contracts or that evolution?

I think there is. I mean, you know, we're working very closely with the customer to deliver better outcomes at the end of the day. And the way you do that is work very closely with the customer. You look at the technologies that you have. You combine that with the types of wells that are being drilled, the challenges that they might be having in a particular area. You combine all that together, and at the end of the day, if we can deliver better performance versus whatever the benchmark is, then essentially we share in those savings. And so it's a real win-win for the customer. Why wouldn't the customer want to pay us more when they're getting wells that are delivered more efficiently, more reliably, and placed better in the zone? So it's a huge win-win. And again, we have customers continue to adopt, and our technology and automation solutions are really helping us to achieve that.

I appreciate the update.

Thank you.

All right, Scott. Thank you.

We'll take our next question from Don Crist with Johnson-Brice. Please go ahead.

Good morning, gentlemen. Thank you for allowing me to ask a question. Good morning. Can I just ask just a term question? Has the attitude of the EMPs kind of ebbed or flowed in relation to term contracts? Are they more willing to sign term today than they were six or nine months ago, given the utilization today? Or how has that kind of progressed through the year?

Don, it... You know, it really depends on a lot of factors. You know, it's very customer-specific, timing-specific. You know, how many rigs do they have running and how many of those they have on term versus how many are on spot. It's really kind of all over the board. You know, from our perspective, our focus is Historically, 50 to 60% of our contracts are termed. Again, you've heard us talk about having 60 rigs rolling off over a two-quarter period. It's really dependent on the customer in many cases. Do you have anything?

No, I agree. I don't think there's been any change in what we've seen, especially with the public company. Customers really having a preponderance for a year term that more or less mirrors their fiscal, mostly calendar fiscal years.

I appreciate that, Colin. Just one more, if I could. I just wanted to touch on the supply chain and kind of where it is today versus six months ago. And more specifically, rolled steel prices have come down quite significantly over the past nine months or so. Are you seeing any of that kind of roll through to pipe pricing? Has any of that started to come down yet?

Don, I think we certainly noticed the steel price peak in 22. And I think that that has resulted in a moderating of price increases. But if you think about the manufacturing that supplies us, just like we needed to increase our margins, I think our supplier base has needed to do the same in order to be able to reinvest in their capacity, because the biggest issue for the industry going forward is scale access to capacity. You know, we've seen a moderation in price increases. I think they kind of are more steady, which I referenced in my prepared remarks about our expectations for, for example, materials and supplies cost being relatively stable this calendar year. So, you know, the good news for us at H&P, though, is about access because of our scale, our uniform fleet. We have direct access to our key suppliers. And, you know, by way of example, as we've mentioned in previous calls, our Don Nottoli, Drill Pipe, our OT full country tubular goods, if you will. We had purchase orders in place by September 30th to fully secure our calendar 2023 needs. So we have that access and I think that that's a key for us in this tight supply chain environment.

Don Nottoli, I appreciate the color. I'll turn it back. Thank you. Don Nottoli, Thank you, Don.

We'll take our next question from Addy Modak with Goldman Sachs. Please go ahead.

Hi, John. Hi, Mark. Your international solutions margin came in better than guidance, and you mentioned the drivers there, but can you give us some color on how you expect this expense to trend over the next few quarters as you work on the Middle East hub?

Sure, Addy. Thanks for the question. We have a rig that's mobilizing to Australia, and that's going to happen, I think, it'll commence in March. We could have sent it sooner. However, it would have been probably stuck at the port due to weather at the time of its arrival, so we elected to just delay its sending a little bit. It's still expected to spud in the back half of our fiscal year. I think the final quarter, And then in particular, I think the bigger focus, as I mentioned in prepared remarks in the Middle East hub, you know, we have a rig that was just delayed there from the first quarter to the second quarter and setting sail. So that's when those mobilization expenses are incurred. And then as we have previously said, as we move through the end of our fiscal year, we have those six walking rig conversions that will be happening essentially April through September. and those will be transited over to the Middle East is our expectation. And again, we wouldn't expect to see revenues from those until fiscal 24. Having said all of that, our expectations for fiscal 23 full year have not changed. It was just some timing from Q1 to Q2 and Q3 in terms of mobilization expenses.

Got it. Appreciate that. And then how do you view the appetite for M&A, whether it's for technology in North America or for expanding your footprint with maybe incumbents in the international markets?

Well, on the technology side, I mean, we're always looking. We feel like we've got a really good portfolio and there's not anything that I feel like is necessarily a gap. From an M&A perspective in the U.S., we've said often that We didn't feel like that made a lot of sense. There's just really not a lot of opportunities out there that we can see from our perspective.

And then anything internationally maybe?

Internet, yeah.

Just like John said, we're monitoring technology. You know, we're monitoring international, and I think if we were going to have an accretive investment, it would probably be in the international arena. We haven't seen it yet, but we're always monitoring, especially with our focus on the Middle East. And then what you're not going to see us do is, as we've said many times in the past, is you're not going to see us consolidate the U.S. market further. It's already consolidated, and we think it would not be a good use of capital to put idle iron behind our own idle iron. and especially dilutive to our uniform fleet in the U.S.

Got it. Thank you for the answers. Appreciate it. I'll turn it back. Thank you.

We'll take our last question from Tom Curran with Seaboard Research Partners. Please go ahead.

Morning, guys. Last but hopefully not least. Definitely. I was curious, for your performance-based contracts, for the portion of the active fleet in the quarter that was working under performance-based agreements, could you tell us what the average premium that fleet realized in the quarter was? And then, you know, I know the premium has been trending around 1500. I think in some quarters it's gotten as high as 2000 a day. How would you expect it to evolve from here? You know, just how much more upside could we see for the performance-based fleet when it comes to that average premium?

Well, you know, I suffice to say, Tom, that it's still in that same ballpark you mentioned, you know, $1,500 to $2,000 uplift per day, what's included in our revenue per day numbers that we've mentioned. And I think the upside is, you know, as we continue to get potentially more of the fleet on performance contracts, if you look at us at HMT, we have over 60 customers. We have two-thirds of our rigs with public companies. And correspondingly, I think about two-thirds to 80% of our performance contracts are with public companies. It also creates some stickiness, if you will, and in some of those public companies, we've We may have had a small percentage of their total fleet, and in a lot of those cases, we now have the majority of the rigs operating in their fleet, and I think it's really helped with customer relationships. John?

Yes, and in most cases, Mark may have said this, but in most cases, we've got some of our technology involved in the performance contracts. And so you've got technology, you've got automation that we're working on, downhole automation. And it's really becoming much more of a trend. And we're seeing more adoption from customers. And so as you think about, you've heard us talk about auto slide and that technology. We've recently rolled out a new advanced auto driller We've got new failure prevention applications. We've got engine automation solutions to help with lowering emissions and improving fuel economy. So as I mentioned earlier, as you look at this from a shared savings perspective and a value creation, customers are more and more willing to share in those savings, which enables us to increase our revenues and really get paid for of the value proposition or a portion of the value proposition that we're providing.

Got it. And that's a nice segue into what was already going to be my next question, which is, what's the current timeline for reaching the next level in rig automation? And just refresh us on what you consider that level to be, John, using you know, the Tesla five level full self-driving analogy. And then maybe could you share some color on specific technology initiatives you have for this year?

Well, if you think about because automation on a rig is you're covering a lot of ground. A big portion of our automation has been focused on you know, manually intensive, you know, type processes, you know, something that using directional drilling as an example where you've got somebody that's requiring, you know, a person 24-7 and being able to automate that and apply algorithms to that has delivered a lot. But there's, you know, all sorts of other things that are, are little automation pieces that are helping the driller, helping the customer do more with less and be more reliable, and not requiring a human to have to pay attention to it, like I said, 24-7. There are automation things that we're working on related to work around the rotary table. you know, lowering exposures related to making connections. There's things like that that we're working on. I mean, this is a very, very long conversation to cover it all. But as far as pushing a button and the rig drilling the next well, we're probably not at that point. Although, auto slide, you push a button and you drill the next stand. But we're a long way from a fully autonomous rig.

Got it. I appreciate that, Collar. I'll let you guys wrap it up.

All right. Thank you, Thomas.

Thank you. I would now like to turn the call back to John for any closing remarks.

All right. Thank you, Nikki. Thanks to everybody for joining us today. I know there's a lot of earnings calls going on this week, so we appreciate your time. We spend a lot of time as a management team looking at pricing dynamics, the sales force looking at pricing dynamics. We're holding the line on capital discipline. We're not chasing market share. We believe that it's crucial to creating a healthy and sustainable company over the long term. Our focus is going to remain on top-tier performance, safety, and reliability, and we're going to continue to focus on improving our margins and returns on capital. So thank you again for joining us today and have a great day.