Stand by. Your program is about to begin. If you should need any audio assistance during your call today, please press star zero. Good day, everyone, and welcome to today's Helmerich & Payne's fiscal third quarter earnings call. At this time, all participants are in a listen-only mode. Later, you will have the opportunity to ask questions during the question-and-answer session. You may register to ask a question at any time by pressing star one on your touchtone phone. Please note this call may be recorded, and I will be standing by should you need any assistance. It is now my pleasure to turn today's call over to Vice President of Investor Relations, Dave Wilson. Please go ahead. Thank you, Ashley, and welcome everyone to Helmerich & Payne's conference call and webcast for the third quarter of fiscal year 2022. With us today are John Lindsay, President and CEO, and Mark Smith, Senior Vice President and CFO. Both John and Mark will be sharing some comments with us, after which we'll open the call for questions. Before we begin our prepared remarks today, I'll remind everyone that this call will include forward-looking statements as defined under 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 10-K, our quarterly reports on Form 10-Q, and our other SEC filings. You should not place undue reliance on forward-looking statements, and we undertake no obligation to publicly update these forward-looking statements. We will also make reference to certain non-GAAP financial measures, such as segment 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 now turn the call over to John Lindsay. Thank you, Dave. Good morning, everyone, and thank you for joining our call today. I'm pleased with our performance during the quarter. The operational and financial results continue to reflect the benefits of our strategic initiatives we've been working on for several years now. In particular, the efforts by our sales and operations teams to improve pricing and margin growth in our North America Solutions segment. On our earnings call last February and again in April, we discussed how rig pricing needed to reach $30,000 per day, and in our third fiscal quarter, we had roughly 20% of our fleet's average revenue per day at or above that level. This is a great start, but we also recognize that pricing needs to move further to achieve gross margins of 50% or greater to generate returns that fully reflect the value we deliver to customers with our FlexRig fleet and complementary technology solutions. As intended, we saw a modest growth in rig count and exited the quarter with 175 rigs contracted in our North American Solutions segment. Fiscal discipline and contractual churn allowed us to recontract rigs without incurring additional reactivation costs and to redeploy them at significantly higher rates. Our rapidly improving contract economics are driven by both H&P's value proposition to customers as well as a market that's very tight for available super-spec rigs. We believe the drilling solutions and outcomes we provide are increasingly being recognized and coveted by customers. It's encouraging to see capital discipline in our industry, and when combined with the supply chain and labor constraints, we expect this could put a damper on the industry's ability to reactivate idled super-spec rigs at significant scale during the buying season. The last two years, that has been in calendar Q4 and Q1. This will likely perpetuate the supply-demand tightness for super-spec rigs and provide momentum for future improvements in contract economics. We are already seeing some customers inquiring about rig availability for the fourth calendar quarter of this year. They are realizing that the market for readily available H&P FlexRigs is extremely tight. We are seeing some customers looking to add incremental rigs for 2023. The needs are typically in the range of one to four rigs, and there are some looking to replace a lower performing rig with a FlexRig. While we are unable to comment on the number of rigs that we could add specifically today, it is important to underscore that going forward, we will apply the same disciplined focus on financial returns and on receiving commensurate compensation for the value we are providing. Along those lines, Mark will provide some high-level remarks on our fiscal 2023 CapEx response to potential future demand for rigs in our idle super-spec FlexRig fleet. We continue to hear about the benefits our customers experience from our digital technology solutions, especially when combined with our uniform FlexRig fleet. As horizontal wells continue to trend toward greater complexity and longer lateral lengths, drilling efficiency and reliability are important factors that differentiate our premium super-spec service offering. On the international front, activity is ticking higher with further improvements in our South American operations and the potential for more activity in coming quarters. In the Middle East, preparations are underway to export some of our super-spec capacity as part of our hub strategy. Current plans have one rig moving overseas in the coming months, with additional rigs possible depending on the speed of the opportunities that develop in the Middle East, compared to other competing international locations. Establishing our Middle East hub is an important step in expanding our presence in that region as part of a longer-term growth strategy. Our scale and digital technology not only enhance profitability in our North America Solutions segment, but we believe these are also crucial elements in our goal to grow internationally. There is a scarcity of digital solutions being applied in key energy-producing regions around the globe, and developing ways to integrate new technologies will ultimately lead to improved economic returns for all our stakeholders over time. In our offshore Gulf of Mexico segment, our people continue to deliver great value for our customers. As mentioned on the last call, we are implementing pricing improvements offshore and have made significant progress. We expect the margin contribution to continue to improve going forward at moderately higher levels. In closing, it is encouraging to see the industry rebound, but it should also remind us of past cycles driven by elevated commodity prices and how the drilling industry repeatedly responded by adding capacity, which then led to an oversupply market. This cycle seems different from both an operator and a service industry perspective. The plan at H&P is straightforward. Safety above all, value creation for customers and margin growth. Getting paid for the value we provide. I'm encouraged by the achievements through the dedication of our employees, their passion, and their service attitude that they bring to the company. We all strive to deliver excellence each day to enhance the value we provide to our customers and our shareholders. As we move forward, I'm confident our shared values and commitments will endure and enable the company to maintain its leadership position within the oil service industry. Now I'll turn the call over to Mark. Thanks, John. Today, I will review our fiscal third quarter 2022 operating results, provide guidance for the fourth quarter, update full fiscal year 2022 guidance as appropriate, look forward a bit to fiscal 2023, and comment on our financial position. Let me start with highlights for the recently completed third quarter ended June 30th 2022. The company generated quarterly revenues of $550 million versus $468 million in the previous quarter. As expected, the quarterly increase in revenue was due primarily to increased revenue per day in North America Solutions segment as we have continued to increase pricing for drilling activity. Total direct operating costs incurred were $377 million for the third quarter versus $341 million for the previous quarter. The sequential increase is attributable in part to the higher average North America Solutions segment rig count compared to the second quarter. General and administrative expenses totaled approximately $45 million for the third quarter, lower than our previous quarter, but still in line with our expectations. During the third quarter, we incurred losses of $17 million related to the fair market value of our ADNOC Drilling investment, which is reported as a part of gains and losses on investment securities in our consolidated statement of operations. Our fiscal year-to-date gains on the ADNOC investment are approximately $48 million. To summarize this quarter's results, due in part to the execution of our strategies to align pricing with value delivered as well as disciplined cost management, we had our first positive net income quarter in 10 quarters. H&P earned a profit of $0.16 per diluted share versus incurring a loss of $0.05 in the previous quarter. Third quarter earnings per share were negatively impacted by a net $0.11 per share of select items as highlighted in our press release, including the loss on investment securities that I just mentioned. Absent these select items, adjusted diluted earnings per share was $0.27 in the third fiscal quarter versus an adjusted loss of $0.17 during the second fiscal quarter. Capital expenditures for the third quarter of fiscal 2022 were $70 million, sequentially ahead of last quarter's $60 million. This is lower than our expectations for the third quarter, but we are still comfortable with the annual range of $250 -270 million that was previously provided. H&P generated approximately $98 million in operating cash flow during the third quarter, which is up over $70 million on a sequential basis from the $23 million in the previous quarter. I will have additional comments about our cash flows and working capital later in these remarks. Turning to our three segments, beginning with the North America Solutions segment. We averaged 174 contracted flex rigs during the third quarter, up from an average of 164 flex rigs in fiscal Q2. We exited the third fiscal quarter with 175 contracted rigs, which was in line with our previous guidance. We added four rigs to our active rig count in the third quarter, including three walking flex rig drilling rig conversions that were completed in fiscal Q3. Revenues were sequentially higher by $77 million due to pricing increases for our flex rigs in the spot market, as John mentioned, and as we discussed on the second fiscal quarter call. Segment direct margin was $168 million, just above the top end of variable guidance, and it's sequentially higher than second quarter fiscal 2022's $114 million. Overall OpEx from the North America Solutions segment increased on a sequential basis due primarily to the increase in average rig count. In addition, reactivation costs of $6.5 million were incurred during Q3 compared to $14.2 million in the prior quarter. Roughly half of these reactivation costs were for the three walking rig conversions added this quarter, while the balance related to additional reactivation costs for rigs deployed at the end of the March quarter. Total segment per day expenses, excluding recommissioning costs and excluding reimbursables, decreased to $15,490 per day in the third quarter from $15,830 per day in the second quarter. Looking ahead to the fourth quarter of fiscal 2022 for North America Solutions, as of today's call, we have 176 FlexRigs contracted, and we expect to continue at that level through the end of the fourth fiscal quarter of 2022. As we stated last quarter, and much like our competitors are doing, we intend to remain within our CapEx budget for this fiscal year, which translates to holding the line on rig reactivations. Our current revenue backlog from our North America Solutions fleet is roughly $629 million for rigs under term contract. Approximately 65% of the U.S. active fleet is on a term contract. Of note, we added approximately 10 rigs to our term roster early in the quarter, which had previously been under negotiation for some time. Between now and calendar year-end, we have over 60 rigs rolling off of term contracts, which we expect to reprice in the current market. The tight super-spec rig supply dynamic is aiding pricing momentum, and we expect the percentage of the U.S. fleet on term to decrease to between 50% and 60% during the next few quarters. As I mentioned last quarter, significant inflationary pressures in calendar 2022, together with supply chain constraints, are increasing consumable inventory costs. Such increases are included in our forward guidance. Note that these costs for consumption of materials and supplies inventory today make up less than 25% of the daily operating cost on a rig with a balance primarily driven by labor. In addition to the inflationary pressures on costs, constraints on supply chain capacity are increasing. In regard to supply chain access to parts and materials, we continue to utilize our proactive approach of detailed inventory planning, scale leverage, and healthy vendor partner relationships to alleviate supply chain challenges in order to avoid a material impact to our ongoing operations. We remain in close communication with our suppliers and have placed advanced orders for items in higher risk categories. Approximately 70%-75% of our daily costs are labor-related. We implemented a wage rate increase in December 2021. Our turnover rates remain consistent with our historical turnover rates. To date, we have not experienced any lost drilling time nor lost contracts due to crewing issues. We are monitoring field labor rates as well as job required out-of-pocket expenditures, and as needed, we will respond to market conditions to assist in talent retention and attraction. As a reminder, our contracts are structured to pass through labor-related increases over a 5% threshold. We have commenced some early reactivation activities for rigs to deploy in fiscal year 2023 to minimize supply chain constraints where possible in our forward planning. Specifically, we are incurring costs to ready components of some of the rigs expected to be deployed in the first quarter of fiscal 2023. Reactivation costs will continue to increase given inflation, but also because the average idle super-spec has been stacked for 2+ years. Our expectation is that reactivation OpEx costs will approximate $1 million per rig moving forward. In the North America Solutions segment, we expect direct margins to range between $185 -205 million, inclusive of the effect of about $6 million in early reactivation costs for the fourth fiscal quarter. Regarding our International Solutions segment, International Solutions business activity increased to nine active rigs at the end of the third fiscal quarter. As expected, we added two rigs in the Vaca Muerta region of Argentina this quarter and added a second rig in Colombia. Also as expected, we incurred expenses associated with the rig startups that I just mentioned, as well as investments made to establish our Middle East hub. As we look forward to the fourth quarter of fiscal 2022 for international, we expect to add two more rigs in the Vaca Muerta region of Argentina this quarter, as well as a third rig in Colombia. These additions will bring our total active international rig count to 12 at the end of the fourth fiscal quarter if the projected startup timing is adhered to. We also expect to incur more expenses as we further develop our Middle East hub, inclusive of preparation to export a super-spec FlexRig that will be targeted at regional drilling opportunities. Aside from any foreign exchange impacts, we expect to have between $4 -7 million direct margin contribution in the fourth quarter, due in part to sequentially higher average activity, reduced startup expenses, and rig rate increases. Turning to our offshore Gulf of Mexico segment. We still have four of our seven offshore platform rigs contracted, and two of our three management contracts on customer-owned rigs are still on full drilling rates. Offshore generated direct margin of about $8.7 million during the quarter, which was toward the high end of our expectations. As we look toward the fourth quarter of fiscal 2022 for the offshore segment, we expect that offshore will generate between $9-11 million of direct margin, a sequential increase resulting from contractual pricing increases on our active Gulf of Mexico platform rigs and management contracts, as John mentioned earlier. Now let me look forward to the fourth fiscal quarter, update full fiscal 2022 year guidance as appropriate, and look ahead to fiscal 2022 planning. As mentioned, we still expect capital expenditures for the full fiscal year to range between $250-270 million, with remaining spend of approximately $85 million at the midpoint to be incurred in the last fiscal quarter. As a reminder, the timing of some spending has pushed to the second half of the fiscal year as key suppliers continue to rebuild capacity that was taken offline during COVID restrictions and the coinciding energy downturn. Looking forward to our fiscal 2023, which begins October 1. While our budget process is still at an early stage, we have done some preliminary work to help frame up expectations going forward. With that said, you should think about our North America Solutions segment CapEx in three buckets, maintenance, reactivation, and conversion. Our bucket of maintenance CapEx costs will likely push to the high end of our historical range of $750,000 to a million per active rig due to inflationary cost increases. The rig's specific reactivation CapEx budget emerges for 2023 as we get deeper into the idled stack of rigs. Here, one-time capital expenditures will be incurred to overhaul componentry that we optimally utilize in the protracted downturn. For example, to delay an overhaul expenditure, we swapped out like equipment from idled rigs during the downturn that had more time remaining before an overhaul was required. This was done in an effort to save capital and defend our conservative balance sheet. Such discrete reactivation CapEx could range from $1 million-4 million for each rig reactivation in fiscal 2023, depending on the particular componentry involved. Over the next few months, we will refine our planning for next fiscal year with the intent of only reactivating rigs for pricing and terms that ensure a return on the significant OpEx and CapEx investments required to bring the rigs back online. The final bucket one should consider is the conversion bucket, which relates to the continuation of our walking rig conversion program. Consistent with how we have been converting rigs to walking rig capability depending on customer demand and projected returns, we will likely do so in fiscal 2023 at a pace of approximately one per month. Our expectations for general and administrative expenses for the full fiscal 2022 year are still expected to be just over $180 million. Items impacting our tax provision and income are at levels that result in a wide variability in the estimated effective tax rate, and therefore the effective tax rate for upcoming quarters may be volatile. With that being said, the U.S. statutory rate for fiscal year 2021 is 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 -20 million for this fiscal year. Now looking at our financial position. Helmerich & Payne had cash and short-term investments of approximately $333 million in June 30th, 2022 versus an equivalent $350 million in March 31, 2022. The expected sequential decrease was largely attributable to our investment in Galileo in the quarter for $33 million, as mentioned during the previous quarter call. Including our revolving credit facility availability, liquidity was approximately $1.1 billion at June 30th. Our debt to capital at quarter end was about 17%, and our net debt was $209 million approximately. We currently expect our trailing twelve months gross leverage ratio to reach our goal of less than 2x outstanding debt by September 30, 2022. Following our resumption of positive cash flow generation from operations in fiscal Q2, the growth of that generation in the third quarter stems primarily as a result of the good pricing work discussed earlier and also due to less reactivation expenditures as rig counts remained relatively steady in North America Solutions segment as planned. On the working capital front, our accounts receivable at March 31 of $330 million grew by $68 million to approximately $398 million at June 30. The preponderance of our AR today continues to be less than 60 days outstanding from billing date, although absolute dollar receivables are up primarily for price increases in North America Solutions, several additional international rigs working, and general price increases in the offshore segments. During the third fiscal quarter, we had a couple of significant cash-related transactions. First, as mentioned in last quarter's call, we invested approximately $33 million in Galileo. Second, we sold our legacy Schlumberger stock for approximately $22 million in pre-tax proceeds. We still expect to end the fiscal year with between $350 million and $400 million of cash and short-term investments on hand. Although we expect to be toward the bottom half of that range, due in part to some working capital lockup from accounts receivables, as mentioned. As we expected, the growth in rig count early in the fiscal year provided a platform for cash generation in the second half of the year. To that point, in the recently completed third quarter, where we fully covered our maintenance CapEx with cash flow from operations, as well as funded our regular dividend. Further, our disciplined capital planning and operational execution excellence sets the stage for cash accretion going forward. Cash returns to shareholders remains a top priority with our existing dividend, and we have a desire to augment these returns in the future. Additional returns are not yet determined by our board of directors, but could consist of an assessment of our long-standing regular dividend, a potential variable type dividend, and opportunistic share buybacks. As mentioned in the press release, our financial stewardship compels us to take a measured approach and balance our maintenance CapEx requirements, growth capital opportunities for both U.S. reactivations and international expansion, and potential additional shareholder returns. More to come on this for fiscal 2023 in the coming quarters call. Note that this concludes our prepared comments for the third fiscal quarter. Let me now turn the call over to Ashley for questions. At this time, if you would like to ask a question, please press star one on your touchtone phone. You may withdraw your question at any time by pressing the pound key. Once again, that is star and one. We'll take our first question from Derek Podhaizer with Barclays. Please go ahead. Your line is open. Hey, good morning, guys. Just wanted to get more of a sense on how many rigs you could add to the market next year. I know you're in conversations with your customers. You mentioned the skidding to walking conversion program in the breakdown of the CapEx, about one per month, call that 12. Just what else do you think you can add to the market just based on your conversations and based on the demand that they're all up and keeping in your framework of generating the returns based on the amount of CapEx and OpEx that needs to be deployed or just love a little more color on that. Yeah, Derek, I can give you some sense of that. As Mark said, we're really not in a position other than to just mention the 12 walking conversions, assuming the demand and the margins returns are there. One way to think about it is what you expect, you know, the rig count to do in the super-spec space next year. Or and really I would say starting in calendar Q4 of this year, because that, again, as I said earlier, that's kind of been the buying season over the last two years. If you think about if you make an assumption that 75-100 rigs get added over you know that 12-month period starting in Q4, if you look at our you know our 25% market share, you know that would be a reasonable range to think about. Again, I think the main point I want to get across is we're not making decisions based on market share. We're making decisions based on the returns that we can generate from these rigs and just making certain that we're getting reasonable rates of returns over a long period of time. Does that answer your question? Yeah, no, that's helpful. Just, you mentioned the $30,000 per day at or above that level, 20% of your fleet's on that. Based on the visibility you had and the rigs coming up on term and the contract term, how can we double that to 40%, 60%? Just the cadence and how long it would take to get the whole fleet up to that $30,000 at $30,000 or above day rate? It's not clear in the prepared remarks, but that 20% was effective the end of our fiscal Q3. That's not where we are today necessarily. That's a fiscal Q3 number. You know, we have pretty clear insight into that. It does take a couple of quarters to get there. You know, I don't think, Dave, that we said anything about what that timing would be. I think, you know, reasonably speaking over a two or three quarter process would enable us to get to that level of pricing, you know, low 30s pricing. I think that's exactly right, John. A couple more quarters. Because as you said, that was a June 30 number you gave in prepared remarks, and here we are not far beyond that, and we're already seeing meaningful accretion to that number a month later. Yeah. Got it. That's very helpful. Appreciate the color, guys. We'll turn it back. Thanks, Derek. We'll take our next question from Doug Becker with Benchmark Research. Please go ahead. Your line is open. Thanks. John, wanted to get your thoughts on a conceptual question. Investors historically have thought about day rates reaching a soft ceiling when it comes back to reactivation costs or upgrade costs. It seems like spot rates are getting above some of those levels, at least on a leading edge basis. Just want to get your thoughts on, is that still a relevant framework to think about pricing, or have we moved into a different dynamic? Yeah, I think the, you know, historical pricing, the context there, it's really different today for, you know, for a lot of reasons. I think when you consider the investments that we have specifically in the super-spec capacity fleet, I think most people want to compare today versus a 2014 time period as an example. As we said in our previous call, that was the last time we had 50% gross margins. We didn't have, you know, 230 super-spec rigs in the fleet at that time. It's a much different situation. Yes, John, I would just add to that, Doug, that, you know, as John mentioned, in 2014 we didn't have a super-spec rig. Going into 2016 and beyond, we invested a lot of money in the upgrading of the fleet, resulting in the industry's largest super-spec fleet, and also resulting in a lot of benefits for our customers. Along the way, we, you know, very oftentimes had what we would consider to be suboptimal returns on invested capital compared to what our weighted average cost of capital is. We're just trying to get back to numbers that make sense financially. This 50% margin is what will get us there. We're on the journey to get to that. Separately, simultaneously, the rigs we built back then, $20 million apiece or even sub $20 million in 2014. Today, rough estimates say that's somewhere between $30-35 million. A lot of capital still to be deployed to the idle assets that have been there 2.5 years plus, which means when we get to the buying season at the end of this calendar year, the beginning of calendar 2023, they'll have been sitting there 2.5 years. A lot of capital deployed for what we estimate to be nearly 150 super-spec rigs in that 2.5 year idle tenure by the time we get to the end of this calendar year. Hope that helps, Doug. No, that provides some good context. Maybe more succinctly, it doesn't sound like you expect a meaningful increase in capacity if spot rates are $35,000 a day or higher because of the framework you've just laid out. Is that fair to say? Could you say that again, Doug? Could you say it one more time? Sure. Just trying to gauge, is your expectation if we see $37,000 a day spot day rates, do we see a big influx of capacity coming into the market? I think the capacity that is out there, as we described, you know, we're estimating around 130 super-spec rigs. We know there's other drillers that are looking at doing some upgrades to SCR-type rigs in order to satisfy demand. I think you know, I would be surprised personally to see all of those rigs reactivated in 2023 for a number of reasons that we've already talked about related to just the supply chain and the capability to be able to provide the equipment sets required to get those rigs back into working, you know, back up to working condition. Because we, you know, as an industry, we've utilized equipment sets off of those rigs that have been idle now, as Mark said, will be for over 2.5 years. You know, personally, I don't think there's gonna be a response. We've had some people ask about new builds, and I just think that, you know, again, based on what Mark just said in terms of a $30-35 million price tag for a new rig, I don't think that's gonna be the case either. Yeah. Take the midpoint, $32.5 million. If you're making $15,000 a day margin, that's a six year payback. If you're making $20,000 a day margin, that's a 4.5-year payback. With the customer base today that has little appetite to contract up beyond their fiscal budget year. Yeah, I think the supply chain thing, as John mentioned, is actually a significant hurdle for any. You know, we're working with our scale and leverage with our suppliers to make sure that we can put rigs back to work, and also keep the active fleet in good working condition. That's an effort that's a lot different today than it was at any time over the last 10 years, so. Perfect. There, it really goes back to just to capital discipline. You know, we've talked about that. That's really the rallying cry within the industry. Our customers are demonstrating it. The service industry is displaying that. You know, there's no reason to rush. Even if the supply chain was there's no reason to rush to try to capture all this, you know, any additional market share that you might be able to capture. You know, one of the things that we experienced in this last quarter, and you heard us talk about churn, we actually had 18 rigs that were given back to us for various reasons. You know, customers, you know, going through their budget too fast, you know, acreage position, the list goes on and on. 18 rigs that were, you know, 18 points of demand that historically speaking, as an industry, we would have tried to satisfy that demand through reactivating something. You know, last quarter, we said, you know, we're going to 175, and in Q3 we're gonna finish the year at 176. We're within our capital budget. That wouldn't have been the case in previous cycles. We would have continued to try to capture additional share. I think that's a really distinct difference in our industry, which I think is really healthy. It's healthy on the operator side, and it's healthy on the oilfield services side as well. Thank you very much. Thank you. Go next to Keith Mackey with RBC. Please go ahead. Your line is open. Hi, good morning, and thanks for taking my questions. Just wanted to maybe start out with the contracting nature. Are you seeing any increased appetite for longer-term contracts from customers that are not necessarily associated with conversion or upgrade? Or are those, you know, hot rigs or whatever you'd like to call them, still on shorter term durations? Keith, I would say it's a mix. You know, we have customers that are interested in terming up rigs or a portion of their fleet, particularly larger customers that you know may have 10 or 15 rigs running. I'm making this up. 10 or 15 rigs running. They don't necessarily wanna term up every rig, but they may wanna term up some rigs. From our perspective, as Mark said, we've got 60 rigs approximately that are rolling off term the next couple of quarters. You know, we'll be looking at those very closely in terms of whether those remain in term or roll over into spot. I would say most of those rigs are gonna probably go into more of a spot type market. I think it's really a mix. We see customers across the board, some that wanna lock up on term, some that would prefer to play the spot market. Got it. Thanks for that. I would just add for us at this time, you know, with the upward momentum of pricing and the supply-demand dynamics of the sector trying to get to the returns that we have been discussing, putting more of our market into the upward mobility of the spot pricing makes sense. Got it. That's helpful. Just curious if you can give us a little bit more detail on the number of rigs you have that could be reactivated within that $1 -4 million CapEx range, and maybe just a little more on your confidence in being able to get additional rigs to the market in, you know, early fiscal or calendar 2023, given the supply chain. Well, we have, you know, from a reactivation standpoint, you know, when we guided to some of the supply chain work that we're doing in this fourth quarter to get ready for putting some rigs back to work, but it's too soon to know definitively how many we'll put into the market. As John mentioned, we're being very cognizant about capital discipline, one, and two, we're not gonna try to meet every demand point that comes our way because we know there will be the existence of churn in the market. In other words, rigs freeing up for whatever reason it may be, I mean, an E&P running out of budget, an E&P running out of acreage, many dynamics. We won't meet every single demand point, if that makes sense. We're still trying to balance. I don't know, you know, the last two years in the buying season, at the end of the calendar year, calendar Q4, calendar Q1, you know, 40 and 44 rigs. These are the last two buying seasons for us to be added. We don't see that level of addition coming. You have to remember that in those two seasons, we were coming off from a substantially low bottom through both the OPEC price change and the pandemic that began in March 2020. A substantial bottom to come back up from. We're approaching numbers from March 1, 2020 today from an activity level standpoint. Don't see the quantum of additions. Said differently, do not see the quantum of additions coming that we had the last two buying seasons. Don't know specifically what that'll be yet. We are working through to know what every single one of our approximately 54 remaining super-specs takes, but not ready to comment on delineating the numbers for all 54 of those at this time. Got it. No, that's helpful. Thanks very much. I'll turn it back. Thank you. We'll take our next question from Arun Jayaram with JP Morgan. Please go ahead. Thank you. Good morning. I was hoping to turn to the international outlook. It sounds like in the near term, you're reactivating a few rigs or adding a few new rigs in Argentina and Colombia, and then transferring one into the Middle East. I was wondering if you could comment on the outlook on some Middle East growth in activity. Do you think customers are looking for more demand before the end of calendar 2022 and initial insights into what we might expect in 2023? I'll start. John, if you wanna chime in. I think, you know, as we think about it, we're looking more over the next two to three years in our planning horizon. If you think about we're always looking at a five year planning horizon, we consider the Middle East scale to be more mid-cycle in that horizon. We're preparing really our Middle East hub, which is to be able to simply have an operating presence and structure in the Gulf countries so that we can respond to demand points that we see coming in that mid-cycle horizon. We are excited about several opportunities we have, part and parcel to the brand presence that we benefited from after the ADNOC investment last year. We're participating in many bid tenders in the region, with NOCs and IOCs alike. It's a little too early to say if we might be successful in one of those tenders, and if we are, you know, that sort of thing is, say, three to six rigs per bidding effort. If we were fortunate enough to win two, that might be six to 12 rigs in the next couple of years, if that's the way to think about it. In particular, the FlexRigs that we have. You know, we've drilled more shale wells than anyone else has globally, frankly. Taking that expertise, especially into some of the burgeoning gas plays in the region, is a really good way to help the customer achieve their goals. Those are the sorts of things we're interested in. John, any other comments? No, I think, you know, we've talked about the unconventional opportunity for really, we've talked about it internationally for many years. We're starting to see evidence that, you know, we're hoping is gonna come to fruition. I would just add to that. I think our, you know, our fleet that's really designed for unconventional work, the performance, the reliability, and the technology solutions that we have, all of those are really complementary to that opportunity set. Great. Thank you. That's very helpful. As a follow-up then on the economics internationally, understanding it might be a little early to comment on the Middle East, but you know, assuming these will be more accretive contracts, you're talking about comparing the U.S. to prior cycle. To what extent is that helpful in our, you know, in our modeling for internationally comparing to prior year margins you've been able to achieve on these rigs, you know, with the higher technology, can we see them exceed those levels? Just any comment you could, you know, help us kind of gauge where we could see margins trend here would be helpful. Well, each one of these bid tenders, for example, that we're participating in, you know, the economics have to be right for us. Our own history over the last couple of years internationally is not. We're not looking to that as any sort of guidance because of the crazy volatility and actually a wind down to zero rigs working because of the pandemic. As we move forward, these things have to be accretive, and we look at the financial returns through time. We also look, though, at the ability to build scale. If we won an initial bid with three rigs, we would be looking beyond that singular bid as a potential new entry point for a new customer for H&P and looking to see what the potential might be for that customer to scale that up, and really get, you know, better absorption rates like we do here in the U.S. through our scale. We're looking at a lot of different components, but I think it's easy to say that it would have to be financially accretive. All right. Thank you. I'll turn it back. All right. We'll take our next question from Tom Curran with Seaport Research. Please go ahead. Your line is open. Good morning. Good morning, Tom. When it comes to the remaining inventory of idle and redeployable super-spec rigs at fleet of 54, you know, there's been a lot of emphasis placed on what you're trying to achieve with regards to converting the psychology around pricing, hitting new levels for leading edge day rate and the associated gross margin. On the terms and conditions side, are you now expecting or do you think you might be able to get some minimal term or, you know, take or pay conditions, maybe an early termination provision? Just wondering how good the remainder of the reactivation contracts might be that we could see. Well, in the US, we will, as I mentioned earlier, we see a movement down from 65% to more to the 50%-60% range for term. For everything we enter into in the U.S. in term, Tom, we do get that take or pay cancellation provision. Having said that, you know, where we are today financially is much different than where we were coming out of a couple of two or three of the more recent downturns. What do I mean by that? We have no debt that's due in 2031. We have a base dividend that's 65% lower than it was going into the pandemic. We have, you know, a substantial amount of cash on hand and look to accrete that. Our capital structure requirements for such take or pay provisions are less necessary than they might have been in prior cycles. We still always like to have some defensiveness, which is why we're still gonna remain within that 50%-60% target range, but give up some term to try to capitalize on the supply-demand dynamic that is creating this push up in pricing and therefore margins for us. John, any other? Yeah. It's, you know, it's always a balance, Tom. There will be some of our walking conversions or probably most of our walking conversions that we will have a term contract commitment. As I said earlier, Mark mentioned, we're gonna have 60 rigs rolling off of term contract over the next couple of quarters, and I would imagine most of those are going to roll into a spot market. You know, we will have some certainty on returns on the larger recommission or the conversions. As Mark said, you know, we're positioned really well to be able to manage through that. Got it. Helpful clarifications. I was wondering if you could give us an update on AutoSlide. You know, the percentage of your average active rig fleet for the quarter of 174 rigs, what percentage of that count do you use AutoSlide at any point over the course of the quarter? I think we're around 25%. I believe that's right. You know, we continue to have uptake. It's, you know, it's been really well received in terms of providing automated directional drilling capacity. As the rig count grows, it's even more important because we're bringing a lot of directional drillers back into the space, and obviously they don't have the experience that a lot of operators would like to have. Just being able to automate that process, directional drilling process is a huge win. We're also able to tie that into a commercial performance-based model that's really a win-win situation for H&P and for our customer. Would you say that the 25% that use AutoSlide at some point, does that 25% contain the entirety of the 20% of the fleet for the quarter that realize average revenue per day of $30,000 or greater? You know, we don't have. That's a great question. I don't have that data. I do know that there is a portion of that that is included in that, but I don't have the data for if it's all 20% or some subset of that. Right. I assume the overlap would be high if not a perfect eclipse. Okay, thanks for taking my questions. Oh, thank you. We'll go to our other question from John Daniel with Daniel Energy Partners. Please go ahead. Hey, guys. Thanks for including me. John and Mark, I think most of us have talked ourselves into believing this is a multi-year upcycle and assuming and hoping that's right. Mm-hmm. I'm just curious, you know, as you look at the pricing, you know, we keep hearing about the low to mid-30s in terms of leading edge. If the rig count, if we actually as an industry add, call it 50-100 rigs over the next 12 months, where does pricing go to? Well, John, obviously, pricing has moved very, very quickly. It needed to move very, very quickly. You know, there was a huge disconnect in the value proposition that we provide, the investments that we have, and the margin generation. If you just look at, you know, previous cycles, obviously, since 2014, we have not been able to get back to that. You know, right now we're seeing leading edge mid-30s. Mm-hmm. Our goal, as we've already said, is to get to the low 30s%. That's really our focus right now in getting to 50% gross margin. It's really hard to say past that, John. I mean, you know, we all read the same materials. Yeah. Out there. You know, there's a lot of people that are surmising where it's going. Obviously we've got a pretty good glimpse into that. But right now we're just sticking to the goals that we've laid out there, and we'll see where it lands. Fair enough. At this point, have you had any shareholders that have advocated pushing activity over price? No. No. Okay. We haven't. That's unanimous. Yeah. Got it. We haven't. Just. I mean, I think, you know, I think there's some that didn't completely follow from our last call that we said, "Hey, we're rig count's gonna be at the most 176 rigs this fiscal year." That was a call a quarter ago. You know, but again, we're really pleased because at the beginning of the year, we thought that same $250 -270 million with 160 rigs, we were able to get 176 out of it. Right. Created some great efficiencies there. You know, expect to continue to see that from us and I think that's what shareholders want, that's what investors want, very much like what our customers are doing. Got it. I got two quick ones, and I'll wrap up. If you said this, I apologize, but kinda do you have a range of where you might exit calendar Q4 in terms of a contracted rig count? Calendar Q4? No. As we said, you know, we're working on reactivations. It's a little too far out to know the definitive demand points. As we alluded to earlier, we will not meet every one of them. Right. Still too early, John. Fair enough. You would expect to be above $176, I presume, in calendar Q4? We would be, yes. Again, you know, I think going back to the question you asked John a minute ago, I think that some folks who maybe had not heard the 176 floor for the September 30 goal of, you know, and holding rigs tight and CapEx tight, which is helping the dynamics of supply-demand and helping pricing, I think that was more on the analyst side. When we speak to investors and one-on-one investors, there's not a single one of them that we've talked to that would like us to go for any sort of share over margin. We're gonna be very cognizant of that theme as we think about your last question and figuring out how many rigs to put in the market in our first fiscal quarter to get to 12/31. Yes. Okay. Well, I'm glad your shareholders are thinking wisely. You've been very generous with your time. It's coming up on the end of the hour. I'll turn it over for anyone else and follow up with Dave afterwards. Thanks, John. Thank you. Thanks, John. There are no further questions at this time. I'll turn the call back over to John Lindsay for any closing remarks. Thank you, Ashley. Thanks to all of you for joining us today. We know there are a lot of earnings calls going on today, and we really appreciate your time. I will tell you, the H&P team, we've already said it, we're laser focused on delivering value to customers and to shareholders. We aim to deliver value to customers through top-tier performance, safety, and reliability. To our shareholders, continued improvement in our margin growth and our returns. Thank you again for your time, and have a great day. Thank you. This does conclude today's program. Thank you for your participation. You may disconnect.