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…

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…

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.

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