Helmerich & Payne, Inc.

Good day, everyone, and welcome to today's program, Fiscal First Quarter 2020 Earnings Conference 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. You may register to ask a question at any time by pressing the star and 1 on your touchtone phone. You may withdraw yourself from the queue by pressing the pound key. Please note this call may be recorded, and I'll be standing by if you should need any assistance. It is now my pleasure to turn the conference over to Dave Wilson, Director of Investor Relations. Please go ahead.

Thank you, Nikki, and welcome, everyone, to Hammer Companions Conference Call, a webcast for the first quarter of fiscal 2020. With us today on the call 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 the securities laws. Such statements are based on current information and management 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 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 forward-looking statements. We also make reference to certain non-GAAP financial measures, such as segment operating income and operating statistics. You'll find the GAAP reconciliation comments and calculations in yesterday's press release. With that said, I'll now turn the call over to John Lindsay.

Thank you, Dave, and good morning, everyone. 2019 was a challenging year for the industry overall. but it is during these seasons when our industry comes together to create stronger partnerships and embrace new ways of thinking and innovation. This is what we're experiencing, and it contributes to our results. Today, we will share some additional context about how H&P's leadership position and performance, both of which continue to improve because of the company's ability to simultaneously deliver incremental value for customers, adapt to increasingly difficult market conditions, and advance the future of automation and drilling. This quarter's results reflect the momentum of shared successes with customers and the company's ability to remain agile and focused on results from our customers and for H&P stakeholders. I'm going to begin talking about our experience with what we are seeing exploration and production companies value drivers. Our customers are looking for every opportunity to invest optimally. They are seeking the best partner with the best expertise and experience that can transcend today's challenging market environment. We strive to align ourselves with the customer's objective to enhance economic returns through better performance and technology. We are working hard to put this shared focus and decision making at the forefront of all of our partnerships. Our strategy is focused on strengthening all of our current customer relationships and building more along the way. We believe technology and automation will be the catalyst for value creation and upstream oil and gas operations. There is power in predictability through reliable and repeatable performance provided by process excellence and automation. And we are seeing that pay off for H&P and for our customers. This concerted effort will continue to set us apart, and I believe it's one of the reasons why we are gaining traction. We see significant value capture opportunities resulting from our autonomous drilling platform. For our customers, maturing basins and normalized well cycle times are drawing more attention to the advantages that wellbore quality delivers. Our automation solutions, specifically AutoSlide, which is automated sliding while directional drilling, have numerous points of differentiation from competing services in the market today. The primary and most customer-centric differentiation is our auto-slide algorithms are tuned with wellbore economics and each customer's value drivers in mind. Specifically, these algorithms optimize the tradeoff between drilling days, time in the hydrocarbon zone, and wellbore tortuosity. As the industry continues to migrate to factory-like drilling, Economically focused automation will be the key enabler. What we have found is this predictability allows for optimization of other key drivers that positively impact the total life of the well. Examples are optimizing completions and providing an opportunity to push the envelope on new methods and techniques that ultimately lead to production increases and lower costs associated with completions. In addition to creating value for our customers through improved well economics, our technologies reduce the environmental impacts of drilling operations by creating more precise and safer ways to maximize extraction, thus unlocking even more value with a smaller environmental footprint. And as we demand at the rig site, fewer exposures at the rig and driving back and forth to the rig. Since 2017, we've made several digital technology acquisitions and have added significant expertise to our team to complete our digital technology strategy roadmap. The first step of that strategy is World War quality and economically focused automation with auto slide. And we plan to launch more levels of our autonomous platform during 2020. We believe we have the expertise and capabilities today to take the next step for our industry without further acquisitions. The power of process automation that drives predictability is paramount for the future of oil and gas. Last year, we introduced the need for new commercial models, where we are focused on creating a win-win value capture for our customers and for H&P stakeholders. Given our customers' focus on spending within budgets, optimizing investment, and value, we are continuing to develop new pricing solutions to reflect the growing partnership between H&P and our customers. These solutions reinforce that approach, enabling us to share in an equitable portion of the value we are delivering. Last quarter, we announced that new commercial contracts made up approximately 10% of our contract mix during the first fiscal quarter, although today we have approximately 15% of our active flex rate fleet contracted under non-traditional day rate contracts, the majority of which are performance-based contracts. As Mark will discuss in more detail in his remarks, These performance-based contracts align H&P's performance and compensation with the customer's goals and provide for a commensurate distribution of the incremental value creation. We are seeing momentum across our primary drilling business segments. As the U.S. land rig count fell during 2019, H&P's market share grew from approximately 22% to over 24%. indicating a growing preference for super spec rigs and the performance these rigs deliver relative to legacy SCR rigs and lower performing AC rigs. Along with market share gains, our quarter end rig count was sequentially higher than the previous quarter's ending rig count. We believe capital discipline by our customers will remain a prevailing theme and we expect industry activity to look similar to the average level experienced during the second half of calendar 2019, which implies a modest increase from current levels. As drilling performance continues to improve, a significant portion of these gains are attributable to the added capabilities and efficiencies from SuperSpec capacity rigs. A knock-on effect of this progress are higher daily maintenance costs and higher capital costs related to the third mud pump, 7,500 PSI capacity, multi-well pad capability, and more horsepower requirements. But that trade-off is well worth it. Our experience shows that over a three-year trend, that super-spec capacity flex rigs can drill 15% to 20% more footage than non-super-spec rigs. Moreover, a super spec flex rig incorporates a number of enhancements that improve safety for employees and reduce the environmental impact at a drilling location. That said, in order to reflect continued efficiency and value gains for E&Ps, revenues for rig services that provide optimized drilling solutions need to increase to cover the cost of increased maintenance and supply and capital costs as well as returns that our shareholders demand. Mark will address the details of pricing more completely in his prepared remarks, but pricing remains firm for flex rigs in U.S. land, and why shouldn't it? Super spec utilization is strong, especially in the most active basins, and the rigs are delivering high levels of performance and value for customers. Before shifting to our international segment, another success during 2019 for H&P was growing our partnerships with the major oil and gas companies. We've grown our FlexRig fleet market share to 16% from 6% at the beginning of 2019, and we believe the company is best positioned to continue to grow our partnerships with the majors and IOCs. So let's shift to our international segment. This quarter also proved to be positive for our business outside of the U.S. We remain optimistic about the opportunities we're seeing in the Middle East, and we were pleased to put a rig back to work in Columbia. Our rigs in the Middle East are now fully utilized, and prospects for further growth in this region are encouraging and would likely result in the exporting of additional flex rig drilling rigs from the U.S. to satisfy any demand. As we hear about unconventional resource plays in the Middle East and South America, our experience, our expertise, and our technologies will continue to put us in a great position to grow in the future. So in closing, financial discipline and maintaining a strong balance sheet are hallmarks of the and set us apart from many industry peers. H&P has paid a cash dividend to shareholders since 1960, and last year we increased the annualized dividend per share for the 48th consecutive year. In thinking about culture and how that can set a company apart in an industry, we are in the midst of a momentous year at H&P. 2020 is our centennial year, and we are using some of this time to reflect our histories. but primarily we're looking at our path forward. In keeping with this milestone, we will remain focused on maintaining our position as the industry's most trusted partner in drilling productivity and technological innovation. Our people have always been dedicated to helping our business through the ups and downs of our industry, and we know that our employees, combined with our rig fleet and technology solutions, are the key to our continued long-term success. And now I'll turn the call over to Mark Smith.

Thanks, John. Today I will review our fiscal first quarter 2020 operating results, provide guidance for the second quarter, update full fiscal year 2020 guidance as appropriate, and comment on our financial position. Let us start with highlights for the recently completed first quarter. The company generated quarterly revenues of $615 million versus $649 million in the previous quarter. The quarterly decrease in revenue is primarily due to a decrease in the average number of RIGs working in the U.S. land segment as expected. Total operating costs incurred were $401 million for the first quarter versus $432 million for the previous quarter. The decrease is primarily attributable to the aforementioned activity decline. General and administrative expenses totaled $50 million for the first quarter in line with our expectations. Our Q1 effective tax rate was approximately 32%, which is slightly higher than our guided range due to a discrete tax expense. Summarizing the overall results of this quarter, H&P incurred a profit of $0.27 per diluted share versus earning a profit of $0.37 in the previous quarter. First quarter earnings per share were positively impacted by a net 14 cents per share of select items as highlighted in our press release. Absent the select items, adjusted diluted earnings per share were 13 cents in the first quarter versus an adjusted 38 cents during the fourth fiscal quarter. Capital expenditures for the first quarter of fiscal 2020 were 46 million. This amount is under our implied guided run rate due to the timing of various projects. Turning to our four segments, beginning with the U.S. land segment. We exited the first fiscal quarter with 195 contracted rigs, which was, as John mentioned, the first time since calendar year 2018 that we've seen a sequential increase in activity. H&P increased its U.S. land market share to 24% by quarter end due to the continued sidelining of less capable legacy rigs in the industry. As John discussed, we expect to see a modest increase in recount during the second fiscal quarter. Pricing remained firm in the super spec market space during the first fiscal quarter. Our average rig revenue per day, excluding early termination revenue, increased to $25,397 for the quarter, which was slightly above our guidance. As a reminder from our November call, this figure excludes our FlexApp offerings, which are now included in our HP technology segments. Summer Companions' average pricing per day varies from basin to basin due to both underlying hydrocarbon economics and competitive rig supply dynamics. Further, as John stated, our pricing is differentiated due to the unique value we deliver our customers as evidenced by our leading market share. In addition to the dynamics specific to each market, pricing variations are also driven by other variables including term coverage and customer concentrations. Our current pricing remains in the low mid-20s with an overall average around $23,000 per day. As a reminder, flex services including trucking, casing running, rental equipment, et cetera, are additive to their rate and are included in revenue per day of $25,397. As John discussed, our performance contracts are gaining ground as a larger portion of the fleet is shifting to this commercial model. As H&P provides value to our customers, such as by reducing their overall well-spread costs, then H&P participates in that savings creation. These performance contracts are now generating approximately $500 per day more in margin than our average day rate model margins produce. The average adjusted rate expense per day increased to $14,987. This is above our previously guided range, primarily due to higher than expected self-insured medical expenses incurred in the fourth calendar quarter, which is the final quarter of the medical plan year. Looking ahead to the second quarter of fiscal 2020 for U.S. land. We exited the first quarter with 195 rigs working, and currently we have 197 rigs turning to the right. Customer conversations lead us to believe that there will be a decrease of approximately 10% in capex spend in calendar 2020 compared to calendar 2019 levels. This implies that the number of wells drilled in 2020 would decline by 2,300 from the 16,400 wells drilled during calendar year 2019, an approximate 14% decrease. To close some of this gap, we would expect to see a modest accretion to the exiting rig count at calendar year end. With that caveat, we are also anticipating that our customers will spend budgeted rig capex at a more even rate throughout this calendar year. Given that, we expect to exit the second quarter with between 193 and 203 active rigs. This would result in a modest sequential increase in the quarterly number of revenue days, which translates to an average rig count of approximately 196 rigs during the second quarter. As the market tightens and as opportunities to displace legacy rigs arise, our initial objective is to put the 45 idle SuperSpec rigs we currently have back to work. Also, we still have 44 flex rigs that are upgradable to SuperSpec when and if market conditions warrant that investment. Compared to the first quarter at $25,397 per day, we expect the adjusted average rig revenue per day to be within a range from $25,000 to $25,500. Our average day rate in both the spot and term markets remains in the low-mid-20s range, and leading-edge super spec flex rig pricing is also at that same level. The average rig expense per day is expected to be in the range of $14,650 to $15,150 for the second quarter. While our overall rig count has stabilized, we will continue to incur costs to recommission idle rigs and or stack out active rigs due to ordinary rig churn across basins. The per day cost here can vary considerably depending on the type of rig and the market dynamics in the basins where the activity is occurring. We will also continue to incur costs associated with maintaining the idle portion of our fleet. At the start of this fiscal year, we elected to set up a wholly owned insurance captive to insure the deductibles for our workers' compensation, general liability, and automobile liability insurance programs from October 1, 2019, forward. Our operating segments pay monthly premiums to the captive for the estimated losses based on external actuarial analysis. The result is a transfer of risk from our operating subsidiaries to the captive for the deductibles, which is our self-insurance retention. We do not expect any significant changes in our ongoing segment per day expenses as a result of this shift. The insurance premiums are included in the operating segment expenses, and are included in inter-segment sales in the other non-reportable segment. These inter-company premium revenues and expenses are eliminated in consolidation. The actuarial estimated underwriting expense for the three months ended December 31 was approximately $8.5 million and was recorded within the other operating expenses line item in our unaudited condensed consolidated segment of operations. We had an average of 129 active rigs under term contract during the first fiscal quarter, and today that number remains 129. We're about 65% of our 197 working rigs. We expect to have an average of 126 rigs under term contract in the fiscal second quarter and earning the current average day rates. 103 rigs currently remain under term contract through the last three quarters of fiscal 2020. Regarding our international land segment, the number of quarterly revenue days is relatively flat in the first fiscal quarter, slightly above our guidance. The adjusted average rig margin per day in the segment increased by $1,731 to $7,208 in the first fiscal quarter. The increase was primarily due to lower than anticipated costs associated with some of our rigs in Argentina, among other factors. As we look toward the second quarter of fiscal 2020 for international, quarterly revenue days are expected to decrease approximately 7% with an average second quarter rig count of approximately 16 to 17 active rigs in the segment. We have been successful in redeploying all five of the rigs we currently have in the Middle East. And while these additions have not been incremental to our international rig count, they have served to mitigate the rigs that have rolled off contracts in Argentina. We remain optimistic that there will be opportunities in Argentina to put rigs back to work. However, the timing is uncertain. The average rig margin is expected to decrease to a range of $6,000 to $7,000 per day during the second fiscal quarter, as decreasing startup costs in the Middle East are more than offset by the impact of idling Argentina rigs rolling off of their five-year NOC contracts. Additionally, we incurred unplanned maintenance expenses during the startup phase of putting an idle rig back to work in Columbia. Turning to our offshore operations segment, we averaged six platform rigs working in the first fiscal quarter. We exited the quarter with six contracted rigs. However, one rig has since been released and demobilized. The average rig margin per day increased sequentially due to the unexpected maintenance downtime incurred in the previous quarter. As we look toward the second quarter of fiscal of 2020 for the offshore segment, we currently have five of our eight offshore rigs contracted. One of those five rigs is in the shipyard as it transitions from one Gulf of Mexico customer to another and is expected to recommence drilling operations in late March. The average rig margin per day is expected to decrease to a range of 10,000 to 11,000 during the second quarter due to the reduced activity. Finally, looking at our H&P Technologies segment, HPT revenues were largely in line with our expectations. HPT operating income was approximately $2 million, when excluding research and development costs of $6 million. We are expecting Q2 revenue for HPT to be between $16 to $19 million, inclusive of FlexApps. As our teams leverage recent successes, we expect continued growth in customer adoption during a stable to modestly increasing recount environment. In December 2019, we closed on the sale of Terabici Drilling Solutions, Inc., resulting in a gain on sale of approximately $15 million. As a reminder, we wrote off the intangibles related to Terabici in the fourth fiscal quarter of 2018. Now let me look forward on corporate items for the second fiscal quarter and the remainder of the fiscal year. At December year end and as of today's call, our revenue backlog from our U.S. land segment was roughly $900 million for rigs under term contract with early termination provisions. Capital expenditures for the full fiscal 2020 year are still expected to range between $275 to $300 million based on our current outlook for fiscal 2020. which, as a reminder, is approximately a 40% reduction to fiscal 2019 CapEx. We expended $46 million in the first quarter, which is less than the implied quarterly run rate of our guidance due to timing differences of procurement activities and project progression. As we mentioned in the press release, asset sales are primarily customer reimbursement for the replacement value of drill pipe that is damaged or lost in hold during drilling operations. These sales offset a large portion of our tubular purchase bucket of CapEx. Our previously communicated expectations for full fiscal 2020, general and administrative expenses, research and development expenses, depreciation, and effective tax rates are unchanged. Now looking at our financial position. Helmer & Payne had cash and short-term investments of approximately $412 million at December 31, versus $401 million at September 31, 2019. We earned cash flow from operations of approximately $112 million in fiscal Q1. The sequential decrease in cash flow was due to several conversion factors, including reduced activity, annual payment of accrued short-term incentive compensation plan, seasonal holiday slowdown of receivable collections, and the payment of the legal settlement that was accrued and disclosed in the previous quarter. We expect cash flows from operations to be higher in the remaining quarters of our fiscal year. Our debt to capital at quarter end is 11%, which is a continued best-in-class measurement amongst our peer group. A reminder, we have no debt maturing until 2025. Our expectations for the remainder of fiscal 2020 include operating activity levels and pricing to generate sufficient free cash flow to cover our selling general and administrative expenses, debt service costs, planned capital expenditures, and current dividends while modestly accreting our cash on hand. Our balance sheet strength, liquidity level, and term contract backlog provide H&P the flexibility to adapt to market conditions, take advantage of attractive opportunities, and maintain our long practice of returning capital to shareholders through our dividends. That concludes our prepared comments for the first fiscal quarter. Let me now turn the call over to Nikki for questions.

At this time, if you would like to ask a question, please press the star and 1 on your touch-tone 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 1 on your touch-tone phone. And we'll take our first question from Jacob Lundberg from Credit Suisse. Your line is open.

Hey, good morning, guys. Good morning. Just to start off, I wanted to drill down on the performance-based contracts that you mentioned. Could you just help us think about how quickly that mix can grow as a percent of your total work? You had a nice increase in fiscal 1Q. Do you anticipate that to continue? And then anything you could provide in terms of your desired mix of traditional versus performance-based would be helpful.

Okay, Jacob, this is John. It's hard to know for sure how we can impact the mix. What I do feel positive about is that we are taking a customer-centric approach to these new commercial models. Every customer obviously looks at things, looks at costs, looks at their particular program a little bit differently. So we're trying to align it with what their drivers are. Most of these contracts have been performance-based contracts, so there's a true win-win for both the customer and H&P in this case. So our hope is that we'll be able to continue to do more of that. One way to think about it is most of the rigs that have the potential of entering into these types of contracts are generally in the spot market rigs as opposed to those that are already under term contract. But, again, I think there's an opportunity for us to do more. As you said, we had a nice improvement contract. You know, our sales force continues to adapt to this. We have, you know, we've made lots of investments in the organization to create the infrastructure that we need to manage these types of contracts. So, again, our hope is to continue to grow it. As far as the total mix, you know, again, that's hard to say as well. But I suspect that as we get more mature contracts, and our customers see the benefits that we'll be able to enter into more of those.

And do you have a desired ultimate mix? Would you go pure performance-based if the market was there, or would you like to maintain some portion of the fleet still on the traditional structure?

Well, I think, you know, Mark had mentioned it in his remarks that our average revenue is higher on our performance-based contracts. Obviously, we're taking some associated risk when you do that. You know, again, it's hard to say what kind of a mix in terms of total, but we're definitely interested in doing more. I think the likelihood, the reality of it, at least anytime soon, to have the whole fleet on performance or some other type of commercial model besides day rates probably isn't achievable realistically.

Okay. And then a follow-up, if I could. Could you stand on the performance-based contracts? Could you just talk about the spread? So if on average you're seeing $500 a day more on the performance-based contracts, what does that spread look like? Presumably there's some jobs that don't go your way, and maybe it's even a negative impact. I would imagine there's some where – it's significantly more positive than 500. So maybe what does that spread look like? And then over time, where do you think you can bring that total average incremental day rate on those contracts?

Yeah, that's a tough one. You are accurate in that, you know, we're not going to If you're talking about a performance contract, you're not going to achieve it every time. Obviously, the goal is to, at the end of the day, to be able to have a higher revenue than what we would achieve with a day rate contract. So we're still in the early stages, even though we've been at this for a year. You know, our industry, in some respects, moves pretty slow on things like this. Yeah, I really want to stress that it is a partnership with our customer. You know, you're only going to be able to have these sorts of arrangements, types of contracts with customers that you have a pretty good relationship with and are able to get in and negotiate something that, again, is a true win-win for both parties.

Do you think it would be fair to say that over time there is an ability to increase the $500 number, though?

I would sure hope so. I mean, we have examples where it's several thousand dollars. Obviously, you do have those that don't work out your way for one reason or another. But again, we're an organization that has a lot of data, a lot of information. I think that we can continue to help our customers drill wells more effectively.

All right, appreciate it. Great quarter, guys. Thank you.

Thank you.

We'll take our next question from Tommy Moll from Stevens Inc. Your line is open.

Good morning, and thanks for taking my questions. Sure, Tommy. So I wanted to start on H&P technology, specifically auto slide, which it looks like is now in six basins. In an environment, in a macro environment, as you – indicated you expect for this year, so maybe slight uptick in rig count, but continued capital discipline among customers. How do you feel about the adoption going forward for AutoSlide? Are we still in the early days where the adoption rate's low, or do you feel like we're getting closer to an inflection point? Well, Tommy, I think... We have had a nice improvement in adoption since September 30. Our auto slide rig count is at 15 today. I think we're around seven. So we've more than doubled since September 30. So we've had some nice adoption. There is, I think, in some respects, Because of capital discipline, there are some adverse effects, I think, that you end up dealing with on the adoption side. And then the other side is just, as we said before, it's a pretty significant change in workflow at the rig site. So there's a real need for change management. But, you know, over the last several months, we've obviously achieved a lot of success. And as you said, we're We're in the sixth basins today. They're the most active basins, and we're having some success, so we are getting some adoption. So our expectation is that we continue to grow. We'd love to be able to lay out for you, you know, what our ultimate, you know, what we would be in each successive quarter, but so much of that really depends on how quickly customers can adapt to the auto slide situation in that we are changing the workflow and we are de-manning in most cases. I think 60 or 70 percent of the auto slide jobs we have today are fully de-manned as far as the directional driller not being on the rig, which is a which is a great thing. It's a great thing for the customer. It's a great thing for the industry because of the reliability piece, less exposure, but it is disruptive. Thank you, John. And just sticking with the technology theme, you mentioned in your remarks that there could be more announcements coming in 2020 on the autonomous drilling theme. I've Expect we'll have to wait for some press releases to get the full details on any of those. But could you give us, even just high level, some of the different pieces of the drilling process that you think are ripe for disruption with some autonomous solutions? I think what I prefer to do, Tommy, is wait and roll it out in a little bit. you know, with greater clarity than what I'd be able to give you right now. But the fact is there are still some highly – there are some things that are done at the RIG site that are highly people-oriented, obviously, and there's a lot of variability in the performance because of the human interaction. And there are things that are ripe for automation, the right for developing algorithms to replace that and to add a more factory-like outcome. So there will be more to come on that. I wish I could tell you exactly when that is, but I think in the next quarter or two we'll be able to have another commercial announcement that will roll in nicely with Autospline. Okay. We will stay tuned for the updates, and I'll turn it back. Thank you. All right. Thanks, Tommy.

We'll take our next question from Sean Miakim with J.P. Morgan. Please go ahead.

Thanks. Hey, good morning.

Morning, Sean.

Morning. Can we talk about the change in quarterly profitability for HP Technologies and how you would be guiding investors going forward? I guess I'm trying to think about the buckets that are driving the change. Is it just absorption on higher volumes? The R&D is separated. Are there mixed considerations? Just trying to think about how to understand the fundamentals, and it's going to be probably a little bit tough to navigate that quarter over quarter.

Thanks, Sean. There are several moving parts in there. And because of that, we're going to keep our guidance for the near term really at a top revenue line item. To your point, there is increased adoption of some products, especially the new auto slide product that John's been speaking of this morning. You also have some price accretion on a per unit basis as we work with different contracting models. Auto slide, importantly, is not on a day rate model. We have various forms of contract, and as we move through some of these early days, we will probably land on the best few forms of contract that are mutually beneficial to the customer and ourselves. So until we get to that point, it's really sort of a top line guidance. Obviously, we have much more discreet internal goals, but those are moving as well as we learn more through this process.

That's very helpful. Are you able to give us any hindsight color on the prior quarter relative to the one before that?

Not at this stage, Sean. Not at this stage.

Okay. Fair enough. Maybe switching to international, could you maybe just give us a sense of what you see as an opportunity set in terms of number of rigs that could be exported from the U.S. over whatever timeframe you feel comfortable with, next 12 months or something? I'm just curious how those latest contract terms are looking relative to prior between Latin America and the Middle East.

Well, as John mentioned, we're excited to put A-Rig back to work in Colombia, and we continue to have marketing discussions in that country. We still, on a long-term basis, are excited about the unconventional play in Argentina. and are being patient there as our customers are as we sort through the new dynamics in that country. We do have rigs rolling off of their original YPF five-year contracts through the rest of this calendar year, and we have been in and continue to be in discussions with IOCs and other players related to the redeployment of those rigs. As it relates to the Middle East, I'd be a bit more cautious, if you will, in trying to provide any specific guidance. We have numerous discussions happening in various countries in the Middle East and are very excited about being able to participate in unconventional plays as they begin to really take shape at scale in some countries there. Excited to be participating in discussions. Those range from preliminary discussions all the way through to the tender type discussions. And it's early days, but we have 45 idle super specs in the United States that are great candidates to put to some of those opportunities when they come to fruition.

But so you wouldn't be able to characterize changes in rates or term at a high level across any of those markets?

Not yet, no. You know, it's the FlexRig we think can really add value in the Middle East, and we also have some HPT trials happening with some of the HPT technology products as we speak there as well. And who knows, as we've discussed in previous calls, the technology could be a rig pull-through. Right. Okay. Thanks a lot. Thanks, John.

Our next question comes from Mark Pionki from Cohen. The line is open.

Thank you. Just following up to the question on HPT and profitability, appreciate that, you know, you don't want to give us any guidance. But if I just kind of assume what we had in the most recent quarter is $10 million of gross profit, and then I take – U.S. land and international and offshore are all at the midpoints of your guidance. I kind of get $210 million of gross profit. I'm wondering what else we need to deduct from that to get to your EBITDA because we've got this insurance thing this quarter that's a new item and then obviously G&A and perhaps R&D from there.

There's several things built into your question there, Mark. As it relates to the, first of all, let me just address the insurance captive. From a segment operating expense perspective, there's no change there. It's just transferring those premiums to the captive. And again, it's intersegment revenue to the captive, which is then eliminated in consolidation. And it's a big self-insurance retention that's deductible, and so we're managing that retention a bit differently through the captive. But from a segment expense perspective, really no change. As it relates to the CPT. Sorry?

Go ahead. Just to clarify, Mark, can I just clarify that just because you're on it on the insurance piece? So of that $210,000 of gross profit that's all in the segments, there's no additional deduction that I would need to make to that to get to your EBITDA as it relates to the insurance.

I know.

And you can see that in the segment reconciliation, which is in the press release, and will be in the 10Q filed later today.

Okay.

And we're going to walk you through the kind of reconciliation offline.

Yeah, I think it's good to talk about it live because I'm getting a lot of questions about it, so perhaps other investors are very interested. Mark, you were going to talk about the G&A and the R&D.

Yes. The G&A, I think you have all the components to get to your EBITDA number, Mark, really. But specific to your HPT question in particular on any more details within there, you know, we have a growing revenue base. As we've said before, we're excited about it because the technology is really software as a service. So in these initial deployments, we're really getting started. We have a bit of a variable operating expenditures. But through time, we expect that to be a really margin-accretive portion of the business, as we've talked about. The G&A related to HPT in particular is pretty fixed, and the R&D is as well. As I mentioned in my opening comments, we don't have any changes to the full-year guidance. Once we get through the technology roadmap that John's articulated – We will, through time, have R&D drop off, obviously, and once you move to a sort of maintenance, if you will, on the software, so you go from version to version as opposed to new software. But that's a bit out in our planning horizon. So if you stick with the numbers we mentioned in November for yearly G&A and R&D, et cetera, you'll be able to get your EBITDA up. Got it.

Got it. That's great, Mark. Thanks. And then just if I could on kind of M&A, I caught the comment that you don't need to do any more M&A to build out the automation capability, but you did make the comment in the press release about having kind of ample flexibility to take advantage of additional investment opportunities. So I'm just curious, you know, what that might be referring to and help maybe set some expectations for M&A for us.

Well, Mark, from an M&A perspective, you've heard in the past what we don't plan to do, which is any consolidation in the industry as far as rigs go. You know, I think the investments that we'll be making are on the technology side. There's obviously the potential to grow internationally as Mark mentioned. you know, continuing to enhance the fleet based upon customer demands, and that's where we're going to be investing.

Got it. Okay. Thanks very much. I'll turn it back.

Thanks, Mark.

Our next question comes from David Anderson with Barclays. Your line is open.

So, John, we're talking about auto slide and how to improve performance and also talking about performance contracts. I'm just wondering how the two work together on kind of the 15% of your business, which is these new commercial models. Are you employing auto slide in any of those contracts yet?

You know, there have been some overlap in bids that we've made. I can't speak to... Any particular right now that we have, but it's definitely in the discussion. To your point, I think it does make a lot of sense as we grow the auto slide functionality and automation in general. I think there is that potential there.

And then also, if we just talk a little bit about the customer mix, I'm just kind of curious, of that 15%, Is that more skewed towards the bigger operators? I'm just curious which types of customers are more receptive to that. Because I also certainly noted how you had talked about your share of the majors had gone up. I'm wondering if those are related.

Really, the answer to the first part of your question is we have interest and have contracts right now with large and small companies. and I expect that that's going to continue. These performance contracts are not related to the growth on the major side of the equation, but I wouldn't rule it out longer term. I mean, let's face it, the majors are very much value-oriented, and I think as they look at ways to enhance value, not only time-based value, but overall life cycle of the well value, I think we have a lot of opportunity to grow there. So hopefully that gives us some opportunity going forward.

Yeah, I certainly think so. I was just wondering if you could just elaborate a little bit about the growth opportunity in the Middle East. I think we just saw the last time I saw it, we had a couple of rigs operating in Bahrain and a couple of rigs either in UAE. Could you just tell us how you think we have five rigs operating in the Middle East today Could you just talk a little bit about where those are? It looks like you react to them in UAE. We just saw an announcement that came out about a big unconventional play in UAE, which I wonder if that's related. And also, if you wouldn't mind just also just telling us, are you qualified in all the major GCC countries in the Middle East, particularly Saudi? I don't remember you ever working in Saudi. I'm just wondering if you're qualified there.

Well, we have, I'll just start us off with the five that you mentioned specifically. I think if you went back a year ago this time, we had one rig working in Bahrain, two idle there, and two idle in Abu Dhabi. And interestingly, last year we closed our Ecuador operation because of its subscale size, and we really have the same size operations in Bahrain and Abu Dhabi, but we purposely kept those open as marketing venues, sensing what could be a developing unconventional play in several countries there. And that's coming to fruition as all five of those rigs are now working, continue to have prospective customers going to visit them as well. And, yes, that's exciting opportunities in many countries there, including the UAE.

And what about Saudi? Are you qualified there?

We do have entities. We do have an entity in Saudi Arabia, a legal entity, I should say, and we have – into the various countries actually in the Middle East.

Thank you.

Our next question comes from Scott Gruber with Cedar Group. Your line is open.

Yes, good morning. Morning, Scott. Question on working capital for Mark. For working capital, it sounds like it should improve going forward. Do you have any color for us on whether working capital will be a benefit or a cash drag? for HP for the full year?

It should improve, as I mentioned in the comments. I think we're going to be relatively stable activity level, so I think working capital will be relatively stable as well, as opposed to being a big benefit or drag, honestly. Having said that, we at H&P are still trying to turn over every rock we can. And we had some successful working capital projects last fiscal year. And this year, we have more that we're looking at, including an assessment of our inventory levels.

Got it. And just back on U.S. land, do you think your rate premium to peers in U.S. land has widened? And not just relative to smaller players, but even relative to some of your bigger, I call primary competitors? Do you think your rate premium has actually widened a bit there?

Scott, I know our other drilling peers, at least I don't believe they've reported yet. I don't know. I don't have the details or the data to know if it's widened. I think in general, you know, we've had pricing discipline. in our sector. As I've mentioned, the rigs are performing at a high level and adding a lot of value. I think in general, it's in everyone's best interest to continue to keep pricing at reasonable levels, at today's levels. Again, I think there's an argument to be made that because of the cost side of the equation and rigs working harder, that there is an element for increasing revenues in order to cover those expenses. Got it. That's it for me.

Thank you. Thanks for the call. Thanks, Scott.

Thanks.

Our next question comes from Chase Mulkeel with Bank of America. Your line is open.

Hey, thanks for squeezing me in. I wanted to come back to the performance base of the new commercial models that you're pushing out to the market. So, you know, if we kind of do some back-of-the-envelope math, it kind of looks like you may be saving, you know, $15,000 to $20,000 per well. You know, could you kind of walk through, you know, the different pieces of cost savings that you're saving for your customer? You know, how much of it is – drilling faster versus kind of taking people off or maybe, you know, cannibalizing some of the other drilling services. So just kind of help us understand, you know, the different buckets for the value proposition to your customer.

Chase, I'd say most of the shared savings are related to time. And as you look at, you know, a real, A real simple example is, you know, 15-day well and two days of savings and, you know, a total spread rate of $150,000 total between those two days. And then, you know, you essentially share those savings. So let's say you split the savings. So on a 15-day well, you know, you've got $5,000 a day. type of additional revenue. I'm trying to give you a simple example. There are other KPI type key performance indicator type models as well where customers want to focus on specific items during the course of the well. I don't have all those at the tip of my tongue right now, but Most of those are areas that they're having challenges and or there's an opportunity for us to come in and perform at a higher level than what our peer would be doing, and we're able to do that by essentially going in with a little bit lower rate and then earning a higher rate.

Got it. Okay. Quick follow-up just on the performance-based contracts. If we think about how you're trying to attack the risk side, if you think about what kind of risk you're absorbing on the third-party service providers, how do you protect yourself there? And then also, you know, with performance-based contracts, it seems like a perpetual kind of resetting of the baseline as performance continues to improve. So how do you protect yourself on that element as well?

Well, that's a very good question. You've obviously seen these types of contracts over time, and there can be some negative effects. results as a result of either resetting framework or the third parties. I think as we look at our experience and expertise and the data set that we have, we have a pretty good handle on obviously the customer that we're working with, the partnership that we share, have a pretty good understanding of those areas that are particularly or have been particularly a problem in the past, and obviously one of those is the directional drilling component. We obviously have significant expertise in directional drilling internally with directional drillers and then obviously auto slide algorithms. So lots of data at our fingertips that we didn't previously have before. So I think it helps us actually work with our customers to – even potentially high-grade, some of the third parties that are working jointly with us on location. So overall, I'm not overly concerned or bothered by the third-party piece of the equation. Obviously, the reset that you mentioned is just something that you have to work out in the contract. But again, as I think about our industry and how we have really – changed and improved over time in that we are working together more as partners with our customers. And I think that, obviously, they want us to win because if we win, they win, right? And so there's an opportunity for both parties to come out in a better place.

Awesome. Good to hear that your customers are willing to work with you. All right. Thanks, John.

All right, Chase. Thank you.

And I will now turn the program back to John Lindsay for any closing remarks.

All right, Nikki. Thank you. And thanks to everyone for joining us on the call today. We really appreciate it. You know, we're looking forward to celebrating our centennial during 2020, as I said earlier. But what we're really doing is looking ahead to our bright future. Looking forward to that. And thank you all. Have a great day.

This does conclude today's conference. You may disconnect your line. Have a good day, everyone.