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Good day, everyone, and welcome to the Helmerich & Payne Fiscal First Quarter Earnings Call. At this time, all participants are in a listen-only mode. Later you will have the opportunity to ask questions during the question-and-answer session. [Operator Instructions] Please note this call may be recorded and I'll be standing by should you need any assistance. It is now my pleasure to turn the conference over to Dave Wilson. Please go ahead.

Thank you, Nikki, and welcome everyone to Helmerich & Payne’s conference call and webcast for the first quarter of fiscal year 2023. With us today are John Lindsay, President and CEO; and Mark Smith, Senior Vice President and CFO. 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 securities laws. Such statements are based on the current information and management's expectations as of this statement 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 will 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 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 2022. We remain focused on our three strategic objectives, which are North America 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 in 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 desires 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 2023, 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 2023 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. 10 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. Second, the idle super-spec fleet has now been inactive for over three years making reactivation and expensive proposition. The third point is that there are roughly 520 super-spec rigs operating currently, which is effectively 100% utilization for those rigs that have worked some time in the last three years. Accordingly, we expect the current utilization of the active super-spec 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 up cycle 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 rollover 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 Solutions 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 US 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 on 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 2023. Preparations to send a super-spec 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 super-spec FlexRigs in the Middle East and other unconventional growth areas without the need to build new rigs. These rigs and our capabilities provide great opportunity to utilize the idle FlexRig 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 results of -- 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 the 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 recognized a loss of $15 million, primarily related to the fair market value of our ADNOC drilling investment, which is reported as a part of loss on investment securities and our consolidated statement of operations. We also decommissioned eight non-super-spec 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 $0.20 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 $0.45 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 the fourth quarter of fiscal 2022’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 9th reactivation that replaced a loss – 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 to being ready for deployment in the first few months of calendar 2023. Total segment per day expenses, including re-commissioning costs and excluding reimbursables excluding re-commissioning 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 expectation, 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 2023 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 US active fleet is on a term contract. As mentioned on our last call, the 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 fiscal Q2 to range between $280 million to $300 million, inclusive of the effect of about $4 million in reactivation costs. As discussed on our 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 supply as 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 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 2023 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 or three rigs working in that country. In the second quarter, we expect to earn $7 million 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 2023 for the offshore segment, we expect that offshore will again generate between $8 million 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 mirrored 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 in other segments. Now let me look forward to the second fiscal quarter, and update full fiscal year 2022 guidance as appropriate -- 2023 guidance, sorry. Capital expenditures for the full fiscal 2023 year, are still expected to range between $425 million to $475 million, with the remaining spend to be incurred over our last three fiscal quarters. Our expectations for general and administrative expenses, for the full fiscal year have not changed and remained 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 US statutory rate of 21%, contributed to permanent book-to-tax differences in stated foreign income taxes. We continue to project the fiscal year 2023 cash tax range of $190 million to $240 million, of which as mentioned in November, a portion relates to fiscal 2022 income taxes to be paid in this fiscal year. Now, looking at our financial position. Helmer Campaign, had cash and short-term investments of approximately $348 million at 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 and seasonal cash outlays, and working capital lockup, which was 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 dividend, 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 four million shares per calendar year. Note, that the Board authorized the repurchase of an additional one million shares in calendar 2023, bringing the total calendar 2023 authorization to five 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 long-standing base dividend and our fiscal 2023 supplemental dividend. Each of these items, stock repurchases and the base and supplemental dividends and 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 to 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. [Operator Instructions] And we'll take our first question from David Smith with Peking Energy. Please go ahead.

Hey good morning. Thanks for taking my question.

Hi David.

Good morning David.

John I'm curious if you could tell us what you've been hearing from customers in gassier basins, particularly -- especially the privates and how the prospect for potentially sustained to low US natural gas prices might factor into your expectations for the trajectory of the US 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 Haynesville 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 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 our 185 active rigs they 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 terms.

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 our returns focused approach. I was hoping you could share some color on what the playbook for this returns-focused approach might suggest in this scenario if rig demand were to come down 5% or 10%.

Yes. David 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 upcycles. I can't -- look as I think back and I look back on rig activity through the up cycles, it tends to be choppy. We've gone through -- I just -- if you just look at the last couple of decades look at the activity coming out of the financial crisis and the pickup in activity and then the choppiness and actually having 100 rigs in the or go down of course we had quite a bit more rigs running then but on a percentage basis it's very similar. And so I think as long as 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 doesn't make a lot of sense to get into a bidding more. 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 color. Thank you.

Thanks David.

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 20, 30, 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, is that the right characterization? And 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 and 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 yes, 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 Saurabh 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-spec 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% utilization level.

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

Yes, yes, no. Yes, yes, 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.

Yes.

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, Saurabh. I think it's as we said last quarter is going to be the same this quarter more or less. If you think about for us, our -- if you look at our term fleet, I think, our average day rate around the term fleet today is around $32,000 per day.

Okay.

And if we look at what we expect this quarter for our average spot revenue per day that's closer to 38.5%. And then if we look at the leading edge, 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. First of all, if you look at the DUCs inventory in the Permian, it's at a very low level right now. Are you seeing anything from your customers that they feel the DUCs inventory is low and they have to build up the drilling inventory?

Good morning, Waqar. We don't get into a lot of discussion on DUC. 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 DUC 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?

John, yes. John, I think you said that's not the thing we've tracked. But clearly, they're very, very low levels and I've heard various customers talk about building those up.

Yes. Great. And then if you look at the capital spending budget of $425 million and $475 million that's a wide range. And what would drive the lower end? Is it just the US rigs that you don't get to about 16 or is it more international that gets you to move between the lower end and the upper end?

Waqar, thanks for the question. A lot of that is timing. I mean think about the midpoint of the range $450 million, if you divide it by 4, you probably would have expected a higher number in the calendar Q1. I mean the fiscal Q1, calendar Q4, we just exited. But these things are lumpy. I mean there are some large purchases like drill pipe orders, et cetera. If delivery moves the wheat, 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. If I look at your rigs in the Haynesville, is there anything in terms of the capabilities, which would -- what requires them some kind of upgrades or anything like that before you can put them to work in the Permian or Eagle Ford?

No Waqar, 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, Waqar.

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

Yes. Good morning.

Hi, Scott.

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. Kind of 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 kind of drive the delta?

Scott thanks for the question. But our margin accretion is just -- is the continual. We've talked about it just a question a minute ago, the moving up of the term rollover through time and that pricing spot continuing is not at leading edge either. We're very -- we have relationships with our customers. We don't just increase week-to-week. 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 pull, 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.

Got you. Yes. 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 kind of what would drive the high-end versus the low-end. So maybe turning to the last point you made on the performance contracts. There does seem to be more appetite to kind of go along on rig contracts. Is that certainly in a sense late last year? Do you feel like there's good continued momentum or maybe even great momentum today on performance type contracts or is that evolution still pretty stay quarter-to-quarter?

I think there is. I mean 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 we share -- 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 place 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.

Got it. Thank you.

All right, Scott. Thank you.

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

Good morning, gentlemen. Thank you for allowing me to ask question.

Good morning.

Can I just ask just a term question or has the attitude of the E&Ps kind of ebbed or flowed in relation to term contracts or 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 really depends on a lot of factors. It's a very customer-specific, timing specific. How many rigs do they have running and how many of those they have on term versus how many are on spot, it's very – it's really kind of all over the board. From our perspective, our focus is historically 50% to 60% of our contracts are term. And again you've heard us talk about having 60 rigs rolling off over a two-quarter period. And so it's really dependent on the customer in many cases. Dave do you have anything?

No. I agree. I mean 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 color. And 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?

I think our – Don I think our – we certainly noticed the steel price peak in 2022. And I think that that has resulted in a moderating of price increases. But if you think about the manufacturing the supplies just like we needed to increase our margins. I think our supplier base as 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. So 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 example materials and supplies, costs being relatively stable this calendar year. So 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 by way of example, as we've mentioned in previous calls, our drill pipe our OT oil country tubular goods if you will. We had purchase orders in place by September 30 to fully secure our calendar 2023 needs. So we have that access and I think that's a key for us in this tight supply chain environment.

I appreciate the color. I’ll turn it back. Thank you.

Thank you, Don.

We'll take our next question from Ati 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, Ati. Thanks for the question. We have a rig that's mobilizing to Australia and that's going to happen. I think that it will 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. It's 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 the prepared remarks on the Middle East hub, we have a rig that was just delayed there from the first quarter to the second quarter in the setting of sales 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 2024. Having said all of that, our expectations for fiscal 2023 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 really -- there's just really not a lot of opportunities out there that we can see on -- from our perspective.

And then anything internationally, maybe?

Inter -- yeah.

Just like John said, we're monitoring technology. We're monitoring international. And I think if we were going to have an accretive investment it'd probably be in 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 but idle hire behind our own idle iron and especially dilutive to our uniform fleet in the U.S.

Got it. Thank you for the answer. I appreciate it. I turn it back.

Thank you.

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

Good morning guys. Last but hopefully not least.

Yeah. 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, 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? Just how much more upside could we see for the performance-based fleet when it comes to that average premium?

Well, I suffice it to say Tom that, it's still in that same ballpark you mentioned 1500 to 2000 uplift per day was included in our revenue per day numbers, that we've mentioned. And I think the upside is, as we continue to get potentially more of the fleet on performance contracts. If you look at us at H&P 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 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 if 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 AutoSlide 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've 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 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 time line for reaching the next level in rig automation and just refresh us on what you consider that level to be John, using 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 manually intensive type processes, something that using directional drilling as an example, where you've got somebody that's requiring a person 24/7 and being able to automate that and apply algorithms to that has delivered a lot. But there's all sorts of other things that 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, 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 -- we're 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 color. All 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.