Good day everyone and welcome to the Helmerich & Payne Fiscal Second Quarter Earnings Call. It is now my pleasure to turn the call over to Dave Wilson, Vice President of Investor Relations. Please go ahead.

Thank you, and welcome everyone to the Helmerich & Payne conference call and webcast for the second quarter of fiscal year 2022. With us today are John Lindsay, President and CEO; Mark Smith, Senior Vice President and CFO. Both John and Mark will be sharing some comments with us after which we'll open the call for questions. Before we begin our prepared remarks, I would like to remind everyone that this call includes forward-looking statements as defined in the securities laws. Such statements are based upon current information and management's expectations as of this date, and are not guarantees of future performance. Forward-looking statements involve certain risks, uncertainties, and assumptions that are difficult to predict. As such, our actual outcomes and results could differ materially. You can learn more about these risks in our annual report on Form 10K, our quarterly reports on Form 10Q, and our other SEC filings. You should not place undue reliance on forward-looking statements. We will also be making reference to certain non-GAAP financial measures such as segments, 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. Good morning, everyone. And thank you for joining us today. Since August of 2020, the oil and gas industry has been undergoing a record recovery from the worst downturn in its history. Just when we thought the environment was beginning to normalize, another geopolitical event, Russia's invasion of Ukraine, unleashed immediate and lasting ramifications. This has provided a sharp reminder to everyone how critical, abundant, cost-effective, and secure energy is to sustaining security and the broader global economy. Given the industry's negative experience in recent years, it should be no surprise to anyone that US producers have remained cautious, rational, and disciplined with regard to their capital expenditures, even in the face of spiking commodity prices. H&P’s strategy is to also maintain CapEx budget discipline and holding that line is something we believe is crucial to creating a healthy and sustainable company over the longer term. The industry rig count increase in the March quarter continued to shrink the availability of super spec rigs that have worked at some point in the last two years. This has compounded the pre-existing supply-demand tension in the market. We were pleased with our progress and momentum during the quarter, which saw our active North American solutions rig count increase in line with expectations, exiting the quarter at 171 rigs after re-commissioning 17 Flex rigs in the second quarter, and 27 in the first fiscal quarter. From here, we expect to see our rig count growth moderate in the coming quarters as there is more rig churn developing in the market. We expect to maintain responsible CapEx spend given the budget we set for the year. You may recall in November, we set our 2022 CapEx budget range of $250 to $270 million. That budget was set at a point in time where we expected to end fiscal 2022 with around 160 active rigs. If everything goes as planned, we now expect our rig count to peak early in the fourth fiscal quarter at 176 rigs while remaining within our CapEx guidance. Like 2021, we have front-loaded our rig activity for our fiscal year in Q1 and Q2 positioning us well for the rest of 2022. Accordingly, we remain laser-focused on improving pricing and creating returns for our shareholders and not on chasing the rig count or market share. That said, we plan to remain the leader in the US plan rig market by continuing to deliver great outcomes to customers and receiving appropriate margin for the value we deliver. Like our customers, we are requiring more from every CapEx dollar spent, and we note a similar trend occurring within the oilfield service industry. This and other factors could lead to the persistence of a tight supply-demand environment for Super spec rigs in the US, which in turn should help move rig pricing to levels more in line with the value we deliver. The economics for our spot contracts are improving at a rapid pace, and we expect similar improvements for our term contracts as they are renewed or moved into the spot market in the coming quarters. As I mentioned on our last earnings call, we believe these conditions could provide a pathway to achieve average spot contract economics in excess of $30,000 per revenue day. We already have many instances of achieving this pricing level in today's contracting activity. Given the increased cost structure of the industry over the past several years, attaining this level of revenue is necessary to garner 50% gross margins, which we haven't experienced since 2014. Assuming the market remains strong, this margin will enable H&P to generate returns in excess of our cost of capital to the benefit of all of our stakeholders. I want to thank our operations, sales, and marketing folks that are working hard to help H&P provide and get paid for the value proposition we deliver. As we've previously noted, the value proposition H&P brings to its customers is enhanced through technology-driven efficiency and wellbore quality. This combined with the current market dynamics is differentiating our performance and accelerating improvements in our contract economics. Mark will touch on our capital allocation strategy, but at this juncture, let me underscore that the company remains fully committed to its fiscally sound and disciplined approach to capital allocation. By continuing to do this, we can maintain our long-standing dividend and pursue opportunistic share buybacks. This also positions us to explore other ways of returning cash to shareholders as more cash is created on the balance sheet. Now shifting to the international markets, the outlook remains positive with additional developments and prospects progressing, even though at a much slower pace than we are experiencing domestically. In our South American operations, Argentina and Colombia remain focus areas, and we have begun to contract additional rigs in those countries. In the Middle East, our strategy and opportunity sets are a bit different. We have delivered some of the flex rigs we sold that are not drilling, and are moving forward with the strong business alliances we established with them. We are also actively pursuing opportunities to export some of our idle super spec capacity into the region. In fact, we plan to start moving a rig into our Middle East hub during the second half of 2022. While we're optimistic about our strategy in the Middle East, we're also keenly aware that this is a long play, and it will take time for opportunities to emerge and fully develop. We don't often discuss in great detail or get a lot of questions about our Gulf of Mexico offshore segment. Our offshore operation has been an important part of our company for over 50 years and will continue to play an important role in H&P’s future. We've achieved many successes over the years and delivered exceptional service to our customers. In fact, some of our most impressive operational and safety accomplishments took place in our offshore operations during the pandemic. On the pricing front, we expect that the margin improvements we're experiencing in the US will begin showing up in our offshore segment in the coming quarters. Our technology solutions continue to deliver clear differentiation and provide very relevant value to our customers both in the US and international markets. We are continuing to grow our automated directional drilling solution as well as automated survey management in combination with our new commercial models. Most recently, we introduced several game-changing solutions to our portfolio: engine management and a suite of failure prevention technologies. Engine Management delivers on our commitment to sustainability efforts by autonomously minimizing excess lecturing engine hours, lowering emissions while also delivering reduced fuel consumption for our customers. Failure prevention automation, such as our newly launched stall assist, protects expensive downhill directional tools, increasing the longevity of those tools that may be hard for operators to source in today's environment. With current supply chain and labor constraints, it also provides consistent and repeatable execution, removing human variability and preventing expensive downhill problems. The key to these solutions is market relevancy, as both of these additions are particularly pertinent to challenges operators are currently facing and align with our focus on delivering better outcomes. Finally, we continue to further our strategy of deploying our capital and expertise to companies playing an active role in the energy transition. We've made selective investments in adjacent industries like geothermal companies that are looking to provide an alternative carbon-free baseload power source. And more recently, subsequent to quarter end, we made a $33 million investment in GALILEO technologies in the form of a five-year convertible note. Galileo has a wide global presence through providing modular, scalable, and portable equipment to capture, compress, liquefy, and transport gas as LNG, basically creating a virtual pipeline. This gas can originate from various sources including wellheads and stranded gas that may otherwise be flared. The opportunity here lies in H&P and Galileo's shared global customer base and H&P’s various drilling sites that have the potential to assist Galileo's growth, particularly in the US. We believe their natural gas technologies and equipment systems have the potential to become increasingly relevant as the global demand for natural gas is expected to increase as an important component of the energy transition. In closing, while it is encouraging to see the industry rebound, we shouldn't be reminded of past cycles with elevated commodity prices, in which the drilling industry repeatedly responded by adding excessive capacity only to reap long-term negative consequences. So far, the cycle is different. During my career, I've never seen a more consistent focus on value creation and getting paid for the value H&P provides. I'm continually inspired by and thankful for our employees, their passion for taking care of our customers, and their innovative spirit that truly differentiates H&P’s offerings in the market. Combined with our Flex Rig fleet and automation solutions, I believe we will continue to lead the way forward in our industry and partner with our customers to create value for both groups of shareholders. And now I'll turn the call over to Mark.

Thanks, John. Today, I will review our fiscal second quarter 2022 operating results, provide guidance for the third quarter, update full fiscal year 2022 guidance as appropriate, and comment on our financial decisions. Let me start with highlights for the recently completed second quarter ended March 31, 22. The company generated quarterly revenues of $468 million versus $410 million in the previous quarter. As expected, the quarterly increase in revenue was due in part to higher rig count activity in North America solutions as operators continued to commit to calendar 2022 drilling activity. Further, we've benefited from rapid execution by our sales and operations teams on necessary price increases that John mentioned on our previous quarter earnings call. Total direct operating costs incurred were $341 million for the second quarter versus $301 million for the previous quarter. The sequential increase is attributable to the aforementioned additional rig count as well as the full quarter impact of the wage increase mentioned in our February 22 call. General and Administrative expenses totaled approximately $47 million for the second quarter, higher than our previous quarter and expectations due in part to non-cash mark-to-market adjustments in deferred compensation that are correlated to our stock price, as well as increased infrastructure spending. During the second quarter, we realized additional gains of approximately $17 million related to the fair market value of our ADNOC drilling investment, which is reported as part of gain on investment securities on our consolidated statements of operations. To summarize this quarter's results, H&P incurred a loss of $0.05 per diluted share versus a loss of $0.48 in the previous quarter. The second quarter earnings per share were positively impacted by a net $0.12 per share of select items as highlighted in our press release, including the gain on investment securities that I just mentioned. Absent these select items, adjusted diluted loss per share was $0.17 in the second fiscal quarter versus an adjusted $0.45 loss during the first fiscal quarter. Capital expenditures for the second quarter of fiscal 2022 were $60 million, slightly below our previous implied quarterly run rate guidance. As a reminder, first quarter CapEx was also below guidance at $44 million. The timing of some spending has been pushed to the second half of the fiscal year as key suppliers continue to rebuild capacity that was taken offline during COVID restrictions. This includes hiring and training of labor and the sourcing of long-lead raw materials such as steel and copper. H&P generated approximately $23 million in operating cash flow during the second quarter of 2022. And we'll have additional comments about our cash and working capital later in these remarks. Turning to our three segments, beginning with the North America solutions segment, we averaged 164 contracted rigs during the second quarter up from an average of 141 rigs in fiscal Q1. We exited the second fiscal quarter with 171 contracted rigs, which was in line with our guidance expectations. We added 17 rigs direct to the rig count in the second quarter, including Flex Rig drilling rig conversions that were completed in fiscal Q2, and 13 skating rigs. Revenues were sequentially higher by $68 million due to the previously mentioned activity and pricing increases. Segment direct margin was $114 million at the top end of our February guidance sequentially higher than the first fiscal quarter's $84 million. Overall OpEx for the North America solutions segment increased on a sequential basis due to the aforementioned increase in our rig count quarter on quarter and the increased wage rates. The reactivation costs incurred during Q2 were $14.2 million compared to the $20.5 million in the prior quarter. These reactivation costs are higher than expected, as we have stated on prior calls. Activation costs increase with the length of time rigs have remained idle. Accordingly, we expect these costs when incurred to continue to increase given that the average idle super spec rig has been stacked for over two years. Furthermore, inflation is starting to put upward pressure on the reactivation costs. Looking ahead to the third quarter of fiscal 2022 for North America solutions, as I mentioned earlier, we ended Q2 near the midpoint of our exit guidance range. As with last calendar year, public customers are holding their activity within their annually budgeted plans. We believe this fiscal discipline will continue until the end of the calendar year when many of these customers commence their annual budgeting cycles for calendar 2023. Due to the reactivation operating expenses and capital expenditures required to reactivate long-idled rigs, we have undertaken two initiatives this fiscal year. First, we are increasing our pricing across the active fleet, and second, we are holding the line on reactivating rigs beyond existing commitments this fiscal year to remain within our fiscal CapEx budget, much like our customers are doing. As we get into planning for next fiscal year, we will only be reactivating rigs for pricing and terms that ensure a return on the significant effects and CapEx investments required to bring the rig back online. As of today's call, we have 173 rigs contracted and we expect to end the third fiscal quarter of 2022 with approximately 175 contracted rigs. Our current revenue backlog from our North America solutions fleet is roughly $534 million for rigs under term contracts. As mentioned last quarter, this figure does not include additional rig margin above the base day rate that H&P can earn if performance KPIs are met once a well is completed. Our focus on pricing is targeted at achieving the pricing levels that John mentioned in order to drive towards 50% margins. Since the pricing peak in 2014, we have not returned to that pricing level in subsequent cycles despite rising operating costs driven by inflation, longer wells, and shorter drilling cycle times. On top of the significant capital investments required to high-grade our US fleet super spec acid, our focus on this margin level is tied to our goal of achieving blended corporate returns that are greater than our estimated cost of capital. Following the unfortunate geopolitical developments since our last earnings call, inflationary pressures on costs, as well as constraints on supply chain capacity, are increasing. While inflation may increase these costs, they make up less than 20% of the daily operating cost on a rig. Our scale also enables us to work with our key suppliers to ensure access to timely deliveries of materials and supplies. In the North American solutions segment, we expect rig margins to range between $150 to $165 million, inclusive of the effect of about $5.5 million in reactivation costs in Q3. Regarding our international solutions segment, international solutions business activity decreased by two rigs to six active rigs at the end of the second fiscal quarter. As discussed last quarter, we idled two rigs in Bahrain due to changes in the customer's drilling schedule. We added a rig in Argentina as expected, but unexpectedly had a rig released, offsetting that gain. International results were above guidance due to multiple immaterial transitory items. As we look towards the third quarter of fiscal 2022 for international, we expect to add two rigs in the Black and Mortar region of Argentina this quarter. We further expect to add a second rig in Colombia this month, getting us to nine working rigs internationally by the end of Q3. Setting aside any foreign exchange impacts in the third quarter, we expect to have between a $3 to $1 million direct margin loss due to expenses associated with the rig startups that I just mentioned, as well as our initial. Turning to our offshore Gulf of Mexico segment. We still have four of our seven offshore platforms contracted and all three of our management contracts on customer-owned rigs are now on full drilling rates versus two on four in April of Q2. Offshore generated direct margin of about $8.3 million during the quarter, which is above the high end of our estimate due to lower than expected costs. As we look toward the third quarter of fiscal 2022 for the offshore segment, we expect that offshore will generate between $7 and $9 million of direct margin, as we will have all three of our management contracts at full drilling rates for the majority of the quarter. Now, let me look forward to the third fiscal quarter and update full fiscal year 2022 guidance as appropriate. Capital expenditures for the full fiscal year are still expected to range between $250 to $270 million with remaining spend of approximately $156 million at the midpoint to be distributed fairly evenly over the last two fiscal quarters. Our expectations for general administrative expenses for the full fiscal year 2022 are now expected to be just over $180 million. The increase in guidance is due to the factors which drove our second quarter results as previously mentioned. In addition, given the stronger than expected market conditions relative to our expectations in November, we have eliminated some previously planned cost-cutting efforts in the second half of the fiscal year to support our higher rig count and our plans for Middle East growth. We will not be providing an estimated effective tax rate range as items impacting our tax provision in income are at levels that result in wide variability in the estimated effective tax rate. With that being said, the US statutory income tax rate for fiscal 2022 is expected to be 21%. In addition, we are expecting incremental state and foreign income taxes and permanent book to tax differences to impact our provision. There is no change to the previously guided range of anticipated cash tax of $5 to $20 million. Now looking at our financial position, we contained cash and short-term investments of approximately $350 million as of March 31, 2022, versus an equivalent $441 million at December 31, 2021. The expected sequential decrease is largely attributable to our January share repurchases, geothermal investments, and some working capital lockup due to increased activity, including our revolving credit facility availability of liquidity was approximately $1.1 billion as of March 31. Debt to capital at a quarter was about 17%, and our net debt was approximately $200 million. We currently expect our trailing 12 months gross leverage term to reach our goal of less than two times outstanding debt during the second half of this fiscal year. Agency’s debt metrics continue to be best in class amongst our peer group. And as a reminder, our sole remaining long-term debt matures in 2031, and our credit rating remains investment-grade. As I mentioned on our last call, as our rig count rises, working capital shows up as a use of funds, which was substantial during the quarter given the addition of 17 rigs. Our accounts receivable grew from $282 million on December 31 to approximately $330 million on March 31. With that as a background, as expected, positive cash flow generation from operations resumed in fiscal Q2, and we expect that to continue to grow through the remainder of this fiscal year. Apart from operations, our first half geothermal investments have been about $14 million, and our investment in GALILEO subsequent to March 31 was approximately $33 million due to these year-to-date investing activities as well as some additional potential investments within our near-term line of sight. As of today, we expect to end the fiscal year with between $350 to $400 million of cash and short-term investments on hand, down from the range of $400 to $450 million guided on the February call. As I mentioned on the February call, the growth in rig count early in the fiscal year provides a platform for cash generation in the second half of the year, starting in fiscal Q3 to fully cover maintenance CapEx and dividends, setting the stage for cash accretion. As John stated, the company is considering capital allocation strategies for any future cash build, including shareholder returns. That concludes our prepared comments for the second fiscal quarter. Let me now turn the call over to Nikki for questions.

I will take our first question from Taylor Zurcher with Tudor Pickering. Please go ahead, your line is open.

Hey, John and Mark, thanks for taking my question. Just wanted to start on some of the market share strategic thought process comments you made a minute ago; they're really interesting to me because we don't, really at least I don't hear of well-capitalized market leaders talking about not chasing market share on the way up when pricing is at a really strong level; that you typically hear about it on the way down when pricing goes to bare bones levels. So just curious if you could give us a bit more color there. And that kind of flush out for us, are customers coming to you asking for incremental rigs to be reactivated in the back half? And you're basically saying, not going to happen this year, but check again in fiscal 2023. And maybe if determined and economics align, we'll do it. Curious on all those topics.

Sure, Taylor, thanks for the question. I'll start and Mark and Dave can chip in. I can tell you to answer part of the question is, part of the reason why we're doing what we're doing is as lessons from the school of hard knocks. We've seen lots of up cycles and down cycles, and the reality of it is we have a tendency as an industry to oversupply the market. At the same time, we also announced back in October, I guess we put our budget together in October, and we announced in November what our budget, what our capital budget was going to be. And like our customers, we think that's a very wise strategy to spend within that budget. We've been very fortunate in that we've been able to really front load our rig reactivations with 27 in Q1 and 17 in Q2, as we just announced. And so, when you think about, back in October, we were hoping to achieve 161 rigs working by the end of the fiscal year, and here we are talking about 176 rigs. So we really outperforming in many ways. And again, I'm going to repeat the front loading is really important because all those rigs that we've put to work that aren't in the chart that aren't turned up that are spot, we're able to move that pricing, and we're going to continue to have rigs rolling off. So we just think it's very wise for us to do that. Our expectation is that if prices remain strong in terms of oil prices and gas prices, our customers will reset budgets again, like they did in 2001 and then again in '22. And we'll be in a position with our first fiscal quarter, fourth calendar quarter to be able to add capacity if the demand is there. Mark, Dave, anything else?

Sure. Just a couple of things. First, kind of an editorial comment. As John really said in his opening prepared remarks, it's a more purposeful growth of margins and profit versus market share growth for growth's sake, so to speak. Our customers are disciplined, and they could grow a lot more than $100 oil, but they're living within their budgets and maximizing their returns; we're doing the same thing. And there's a lot of churn in the market right now. So adding capacity in the face of that, as John said earlier, just does not seem like the right capital discipline to us. Further, a little more technically, adding an incremental rig to the market is more than just about pricing and market share; you have to consider the full OpEx expense and the capital expenditures required to bring that rig to market together with the length of the commitment or contracts. Are you going to be able to recoup the investment through the term of the contractor? That together with foreseeable pure line of sight to future work; that's a little harder in this current environment where customers budget calendar year to calendar year; higher and higher activation costs just have to drive higher pricing. Anyway, we're trying to get to a capital-efficient rate here to reactivate rigs. And we also have to just consider the longer-term view.

Understood and on all those fronts, and thanks for the detailed response. Just a quick follow-up on pricing. So obviously now, we're in a pretty constructive pricing backdrop. You’ve been campaigning the performance-based model for a number of quarters now, years now. And I guess I'm curious in this sort of pricing backdrop, is it conducive to more adoption of performance-based models or do customers start going away from performance base and back to more of the traditional pricing models in this day and age?

Well, Taylor, we still have 40% of our rigs that are on performance-based type contracts, and we've had that now for several quarters, obviously, much improved from when we very first went on this journey two years ago, like you mentioned. So we continue to have customers that are really true partners that are working, we're both working very closely together to provide greater value, improve well cycle, improve wellbore quality, wellbore placement, enabling automation solutions, lots of things that we're working on together to deliver better outcomes at the end of the day for the customer. They're willing to share in that. I will say that it doesn't always work with every customer; with some customers, for whatever reason, it's harder to partner, and we go back to a more traditional contract structure, which is fine. As long as we're able to generate the types of margins that we've talked about that are really needed for us to continue on this journey to become more and more investible as a company. So, as you can imagine, it's a pretty large, in terms of the types of customers. But what's great about it is both large and small super majors; we've got a very wide range of customers that are participating with us in these new commercial models, and it's delivering a lot of value. So my expectation is that it's going to continue to grow and become more popular.

And we will move next with Douglas Becker with Benchmark Research. Please go ahead.

Thanks. Hypothetical, if all your rigs were magically on the current leading-edge economics, what's a realistic margin per day that could be achieved, given regional pricing differences, cost differences, rig specs, contract differences? I'm just thinking about back in 2014, there were a few quarters where we did see $15,000 a day. And so I'm not trying to get too far over my skis, but just want to give a little context about what's kind of realistic, just with the economics we see today.

I think just high level, our answer would be we would be in a position to generate 50% gross margins. Again, if you look back at 2014, we were generating on average 50% gross margins; the differences in the cost structure was $3,000 or $4,000 a day less than what it is today for lots of reasons. I mean, in 2014, we might have had a handful of super spec rigs. Today, every rig with the exception of two that's running for us is super spec capacity; much more investment, the rigs are running much harder, the expendable, everything we're using; it's driving the cost. But at the end of the day, it's delivering greater value for customers. So that's really the goal. So I think that would probably be the answer. Mark, you agree?

That's helpful, and then fully appreciate that market share is not a target; it's not a goal. But as we think about next calendar year, would you conceptually or high level expect to kind of maintain the market share or is that really just a complete secondary consideration? It was much more about getting the right type of returns on what's currently deployed?

Well, Doug, you've seen us coming off of the bottom out of the downturn; we had lost some market share based on our primary customers that kept their rig fleets the most. So we've caught back, and I think we actually have more market share today than we did. So it's not that in certain parts of the cycle market share isn't important. What we're saying is right now, what's most important is generating the margin that we need and living within the budget that we told our shareholders or investors that we were going to live with them. So that's most important. We've said this all along; we said it in 2021, and we're still saying it that 2022, we at least we expect is going to play out very similarly to 2021, where the fourth calendar quarter we’ve got a lot of rigs going back to work first calendar, quarter a lot of rigs going back to work, then it gets a little flatter; you get choppy; a lot of churn. Mark had mentioned something about that. We've had, I don't know, six or seven rigs that would have been given back to us for various reasons, and we've been able to place those rigs with customers that have programs. So that’s worked out really at much higher rates and obviously, very much higher rates. So as we think about 2023, which will be here, before we know it, we'll be resetting our budget in October like we did in past years. Our hope is that we'll be able to add additional rigs in 2023 in, in calendar Q4 and Q1 again, we hope it plays out like that; obviously, you know, we’ve got a lot of work ahead.

And I would just put a note that, Doug, by adding that, given our focus on value proposition to customers and our sheer scale with the most idle capacity super spec capacity in the United States, we absolutely expect to maintain or increase that market share cycle.

We’ll move next to Ian Macpherson with Piper Sandler, please go ahead. Your line is open.

Thank you. Good morning, John and Mark. I'm picking up attention here that needs to be resolved. Every quarter, what we're witnessing is that your cycle is moving up more sharply faster with activity and so far and with pricing and margins. And at the same time, we know, as recently as our conference last month that big E&P's are loath to lock in current rates. They don't want term contracts at $30,000 a day. But we hear resolutely from you and your peers that no one's going to build rigs. And we know we're going to run out of high spec rigs in a matter of quarters. So that's a big gap that needs to be resolved. And it probably needs to be resolved with multi-year contracts that your 50% margins are low to mid 30s day rates right now. When do you start to see some narrowing of that gap and in attitude towards locking up these rates on multi-year term?

I'll address a couple of things. And I'll have Mark and Dave, kick in additional comments. First of all, I hear what you're saying about the available super spec fleet. But the reality of it is, there's still a lot of capacity out there; I don't think that we're going to be in a situation where we're going to be building or needing to build new super spec rigs. You'd mentioned a couple of quarters; I think it's going to take, well over a year at the current type of activity gains. We don't know for sure how budgets are going to be reset for 2023; we have some view of the rest of 2022. So, for us today, our preference is to not lock into more term; our preference is to continue to move pricing up in the spot market. At some point in time, I think we do have some customers that have locked into pricing above the high 20s, above 30. And you can get insert using our technology solutions to push pricing higher based on the value proposition that's delivered. But I would be surprised. But Mark, what would you add?

No, I think you hit it, John. I think it's a combination of we're just at the right spot in the cycle. We expect our customers to hold flat this next two quarters going into the fiscal first quarter of 2023 for us final calendar quarter of this year and sort of resetting their in their new budgeting season just as they have that just as they did at the end of 20 going into 21. So while we're at this flat level, and we're seeing churn, still demand for rigs, we have to move the pricing up, as Jonathan said. And then I think at some point in the future, once we started moving in that direction across more of our average fleet rate, at some stage then we'll have the right juxtaposition of the ability to set term based on that higher pricing, but we're just not there yet.

Yes. And one other thing to add, I don't think I said this, which is, as we start thinking about 2023 and calendar Q4, we would be reactivating rigs that have been idle for over two years. So the recommissioning cost, whatever CapEx, no, it's not a new build; but it is additional cash that up to this point, in many cases, we've self-funded that. And so, we would be looking at that situation with higher prices and a term contract commitment in order to reactivate those rigs as well. I'm thinking about it right now.

Understood, thank you, gentlemen. And then as my follow-up, Mark, you alluded to seeing some upside to your Gulf of Mexico operations, not too far out. And I think also when you get to the end of this fiscal quarter with plus three more rigs in Latin America, that should probably have a better run rate than what you've guided for fiscal Q3. Can you describe what those upsides might be in the following quarter or quarters as you get ramped up in those secondary markets?

Thanks for the question. And I think it's a little early; as we mentioned with international, adding two rigs in Argentina and one in Colombia, we're going to have a lot of costs associated with those startups in Q3. But to your point, the absence of that will help going forward. We're still in negotiations for additional rig ads in both of those countries. So depending on how that shapes out, we can have again more abnormality, transitory costs over the next couple of quarters as we continue to add to that rig count, but build us up well for future cash flow generation in the absence of those reactivation costs, just like we've had in the US. In offshore, I think the potential there really goes to John's comment on his prepared remarks, and that is about how we need to work on pricing with our harvest offshore segment. Hopefully, that's helpful.

We'll take our next question from Waqar Syed with ATB Capital Markets, please go ahead.

Question on new build rigs. I know we talked about that maybe you don't have a number. But what is your expectation that if you were to order a new build rig, what would it cost a day based on the current requirements of a rig? And then what kind of margin is required to justify building a new rig?

Let me just jump in for a second? Thanks for the question. But I have to tell you, we haven't asked that question. We had 60 idle super specs, and we like to put to work with a heck of a lot less investment in a new build rig. And for all the right reasons that we've talked about with returns on capital, returns on the half backs, and the right pricing margins to get us to return on capital employed as a consolidated corporate entity. So we have a lot of focus on that as we move through time here.

But let me ask the question another way, that is when you get to this $30,000 type of revenue per day, that gives your competition or somebody else in the industry or private equity, anyone else, the financial incentive to build the rig?

We've seen a couple of those pop up over the last 10 years; if you look at the results of those companies that have done that, not great. So I find it very hard to believe that we're going to see somebody jump into this business or start to invest in new builds when there's the number. I mean, there are 150 super spec rigs that are idle on the sideline today that have been idle for over two years. And so, let's face it, regardless, let's think back to the why behind the new builds that we started, back in 2004 or 2005 timeframe. It was a replacement cycle. We had rigs that were old that were built in the 70s and 80s. We're not faced with that today; we've got a rig fleet, an industry-wide rig fleet that may have lots of different variations; but at the end of the day, they have a lot of capacity. Now we're going to have to reinvest in those rigs that are idle, because a lot of that equipment has been used to maintain the working fleet. I think everybody is pretty well established that that’s been going on. So I just find it very hard to even imagine that somebody would be able to get the backing to start a new company or to build new rigs with the amount of excess capacity that's on the ground right now.

That's great. Thank you. And just my second question, you've been investing in R&D to flip over around $25 to $30 million a year for several years now. How do you internally measure the returns on that R&D investment, and what's your view of how well that has served you those investments?

Thanks for the question. I'll take a stab at that. It's that technology, and then that digital software that we have focusing on downhole operations improvement for our customers, as we've long talked about straighter and better placed wellbores, which actually help with our customers' overall total cost of ownership of a well. We as a driller are about 20% to 25% of an APC for well, and we can affect a lot of the other 75% plus costs with the drilling in a better well. I think that's proof evident in our uptake in performance contracts. Because in those, as we've talked about, this last year or two, if you think about it just at its basic administrative from an administrative perspective, we used to have a read contract and several separate forms of contract for various software. Today, we have with the performance contract, a single contract where we work with the customer to set KPIs together and pull through the technologies to achieve those KPIs and to reduce overall well costs. So I think the uptake from a couple of years ago, not having performance contracts to the day having 40% of the fleet on those; and it's those contracts that are driving the $30,000 plus revenue per day, really at the top end of our fleet, and helping us to get to the margins that we've talked about that we need to get to John, if you have any.

I think this industry is going to continue to trend toward utilizing digital technology algorithms and automation to do what have expensive have been relatively manually intensive. Obviously, we focused a lot of attention on directional drilling technologies. But we've made some great acquisitions; we're going to continue to have a strong R&D budget. And hopefully we are able to maintain a strong market going forward; as you can imagine, through since we've been deploying this technology we've had some pretty difficult markets, but we're starting to see even more traction.

Next is Derek Podhaizer with Barclays, please go ahead.

Hey, good morning, guys. Just wanted to continue the line of questioning, you showed considerable term contract backlog uplift. You talked about the dynamics on the willingness of both you and the end to lock up breaks for longer in the coming more from your side of things or more from the E&P side? And given the backlog that you see now, do you have line of sight to reaching those 50% gross margin targets?

Thanks for the question. We had some additions to term in this press release that was filed yesterday, and a lot of that really took place in January. Frankly, it's been a fast-moving market in those contracts that were in the in the queue and the press release were negotiated in really in the fourth calendar quarter, heading into this calendar year. So that really took in January and since then the February call where John discussed our need to update pricing. We've really since then entered into spot contracts focused on getting rates up across the fleet. Further, as terms rollover, we're not as likely based on the comments we've said this morning to not be as likely to re-up that term; we're focused more on getting appropriate pricing if left with the current spot.

Okay, guy, that's helpful. Caller that makes sense. I want to switch to international. He talked about the Middle East today, and you talked about the ultimate goal of that; maybe the regions and types of rigs you want to send over other technology pull through. Maybe what the required rate looks like in that region, would you need to upgrade some of your idle rigs for spec, for example? They just need just some more color and details around? I know it's a long play. But what do you ultimately see as the Middle East hub looking like?

If you think about something like the Permian, from the eastern Midland into the Western Delaware, it's a long geographic space. The Gulf Coast countries, we're thinking about approaching that from a yard or a hub perspective, not unlike we do with the Odessa operation that we have. And as we look to the long term, we've spoken about this for a couple of quarters; I think the Middle East has had a really steady recount, compared to the volatility of the US shale play over the last 15 years; there's not really been a rig replacement cycle there. You couple that with what is a burgeoning gas play with several countries in the region, including for their own energy strategic gas independence reasons, as well as potential LNG export reasons. So that is a different kind of drilling; it's horizontal, and we believe that really fits our super spec Flex Rig quite well, providing an opportunity to shift capacity. We, after the ADNOC transaction last year, really increased our presence from a marketing perspective and hiring boots on the ground sales folks in the region. So if you think about it, as you said, international timing is hard to predict; we're still developing a lot of resources to move the ball forward if you will. But we do plan to send over a rig during the second half of this fiscal year that John mentioned earlier, and there will be initial costs associated with that. We were quite comfortable with this, given the longer term opportunities, it's sort of setting up, if you will, a showroom floor to show off our product. And we are actually participating in several bids and tenders with different players in the region; these things take a while to move through time to get settled. But if we're successful, even with just one of them, that could be a three to five to six rig addition for us. So stay tuned; we're being patient and are really planning to look at that as a way to reduce the US concentration rather than we've had historically, as of recent time.

That's all appreciate the comments. I'll turn it back.

We'll take our next question from Connor Lynagh with Morgan Stanley, please go ahead.

Yes, thanks. I've got a high-level question that I frankly know is borderline impossible to answer. But I'm going to just get your thoughts on it anyway. You've got all of the big red contractors reporting earnings over the last 24 hours here. And there's not a very significant activity increase contemplated in anyone's third quarter outlook. I'm curious; there’s as I can see it three big reasons why activity wouldn't be growing given where oil prices are. One is the EMP sticking to their capital budgets. The other is the supply chain bottlenecks that we've seen out there? And the third is the service companies sticking to their capital budgets, like you guys are highlighting here, raising pricing. So I'm curious of those three, how big do you think each is contributing to the lack of activity growth we're seeing given how robust oil prices are?

I think most of what contributes to the behaviors that you're saying all really go back to the EMPs and their capital discipline. Again, if you look at how the budgets that were set in 20 going into 21, and the type of activity that we had; 22 is playing out very similarly. And it's, they're setting budgets and they're sticking to their budgets. And if you look at it, I've seen I think most DNPS public A&P set their budgets at a $55 to $60 oil price environment, obviously, much stronger pricing than that, but they've stuck to it. And what's great about that is that it does enable you to plan your business better. I know, at least for H&P, we haven't, our rig count growth isn't related to supply chain challenges, even though there are supply chain challenges. It's not related to people; we've done a great job acquiring people, and our folks just continue to do a great job. It's really driven by the EMPs, our customers at the end of the day.

Got it. And I appreciate it's very early on this front. But, just in your conversations with customers, do you feel that there is a willingness or desire to grow within their stated frameworks, i.e., grow CapEx within their stated allocation frameworks? Or do you think they're more sort of thinking about the production growth that they've promised the street, which variable do you think they're solving more for?

I think they're intending to live within their CapEx budget; in that CapEx budget that they announced had anywhere from no growth to 5% growth, depending on the customer, and that's their expectation. And I don't see any indication that there's any change at all with the large public players, and quite frankly, even the private companies; we keep hearing about this wildcard that the privates are just going to go ramp up production, and we just really haven't seen evidence of that. I think there's a lot of discipline associated with those companies as well. And, again, I just think it sets us up for a much better outlook as an industry. And we haven't done a good job in the past and doing that. But I really believe, like we've talked about, that we're on a course to continue to go down this path.

And we will next hear from Goldman Sachs. Please proceed.

So just in light of comments on capital discipline, from you all, I guess, in the prepared remarks, can you provide some color on how we should think about non-maintenance CapEx beyond fiscal 2022? So would that non-maintenance CapEx primarily include just the walking rig conversions going forward? Or are there going to be ongoing other CapEx commitments beyond that?

We're obviously not in budget season at this stage. And we really haven't made any decisions. We’re just starting to get into looking at that. So, our preference would be to hold off and talk more about that. When we get into budget season, it's still really early in the game to do that right now. What I will say is just no more than what I said earlier, which is, everybody in the industry, their idle capacity has been idle for over two years, and much of that equipment has been used to maintain and upkeep other rigs that are running; why invest in new capital when you can use something you already have in the ground? So obviously, and as we've seen through the very beginning, coming off of the downturn, there early rigs that were reactivated cost $50,000, $100,000; it wasn't much to do it, they were ready to go. But that cost continues to get higher. So more to come on that.

Sounds good. Thank you. And then just one follow-up on your customer mix. I imagine, I guess, it's more weighted to the privates now than it's definitely before the pandemic. Do you expect that that mix to materially change going forward? Especially as we get into the budget refresh these and into Calendar 2023? And is there sort of a, how is the difference in dynamics with your private customer base versus your public customer base historically? Is there any sort of big change now that we should see as we think about this cycle?

Well, we actually have a larger percentage of our fleet working for public companies than we do private companies. I think we're probably the only or one of the few that has that in our space. But we have grown our private company customer base significantly. We are the largest market share and rigs running for Super majors for large public E&P's as well as for privates. But there's a dramatic range between where the private company is much, much lower percentage; anything you want to add?

The only thing to add is within the private group, customer base, there's different operating styles; some of them will do want to have visibility, will want to determine long-term, as far as different contracting styles between private and public. So some of those contracts and styles for the private mirror the public's and other ones; they just have short-term work. So that's kind of the main difference that I see from a contract perspective.

And this does conclude our Q&A session. I will turn the call over to John Lindsay for any closing remarks.

Thanks for the questions; they were very helpful. As you heard us say we're very optimistic about the future. We're very pleased with the momentum that we've garnered this past year. As you heard us say we are focused on margin growth, we're focused on returns, and we're focused on continuing to provide an elevated performance proposition for our customers. And so we're very excited about that. We're happy to have the folks we have at H&P; thanks for everybody's contribution, and we'll talk to you next quarter. Thank you, have a great day.

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